10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended	December 31, 2020
	OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from                      to

Commission file number 1-7584

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Exact Name of Registrant as Specified in Its Charter)

Delaware		74-1079400
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
2800 Post Oak Boulevard
Houston	Texas	77056
(Address of Principal Executive Offices)		(Zip Code)

713-215-2000

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes  þ    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☑ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes   ☐     No  þ

DOCUMENTS INCORPORATED BY REFERENCE

None

REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (I) (1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K WITH THE REDUCED DISCLOSURE FORMAT.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

FORM 10-K

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	3
Item 1A.	Risk Factors	7
Item 1B.	Unresolved Staff Comments	21
Item 2.	Properties	21
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	27
Item 8.	Financial Statements and Supplementary Data	28
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures	57
Item 9A.	Controls and Procedures	57
Item 9B.	Other Information	58
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance (Omitted)
Item 11.	Executive Compensation (Omitted)
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters (Omitted)
Item 13.	Certain Relationships and Related Transactions, and Director Independence (Omitted)
Item 14.	Principal Accountant Fees and Services	58
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	59
Item 16.	Form 10-K Summary	61

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DEFINITIONS

We use the following gas measurements in this report:

Mdth – means thousand dekatherms.

Mdth/d – means thousand dekatherms per day.

MMdth – means million dekatherms.

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PART 1

Item 1. Business

In this report, Transcontinental Gas Pipe Line Company, LLC (Transco) is at times referred to in the first person as “we”, “us” or “our”.

Transco is indirectly owned by The Williams Companies, Inc. (Williams), a publicly traded Delaware corporation.

GENERAL

We are an interstate natural gas transmission company that owns and operates a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. Our principal business is the interstate transportation of natural gas which is regulated by the Federal Energy Regulatory Commission (FERC).

At December 31, 2020, our natural gas pipeline, which extends from Texas to New York, had a system-wide delivery capacity totaling approximately 17.9 MMdth of gas per day. During 2020, we completed one fully-contracted expansion and began partial early service on two additional fully-contracted expansions, which added more than 0.5 MMdth of firm transportation capacity per day to our pipeline. The system is comprised of approximately 9,800 miles of mainline and branch transmission pipelines, 57 compressor stations, four underground storage fields and one liquefied natural gas (LNG) storage facility. Compression facilities at sea level rated capacity total approximately 2.3 million horsepower.

We have natural gas storage capacity in four underground storage fields located on or near our pipeline system and/or market areas, and we operate two of these storage fields. We also have storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to us and our customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 194 MMdth of gas. At December 31, 2020, our customers had stored in our facilities approximately 148 MMdth of gas. Storage capacity permits our customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

MARKETS AND TRANSPORTATION

Our natural gas pipeline system serves customers in Texas and 12 southeast and Atlantic seaboard states including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey and Pennsylvania.

Our major customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on our pipeline system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Our three largest customers in 2020 were Dominion Energy, Inc., Duke Energy Corporation and The Southern Company, Inc., which accounted for approximately 10.0 percent, 9.4 percent and 8.7 percent, respectively, of our total operating revenues. Our firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible transportation services under shorter-term agreements.

Our facilities are divided into eight rate zones. Five are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production–area transportation is gas that is both received and delivered within production–area zones.

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PIPELINE PROJECTS

The pipeline projects listed below were either completed during 2020 or are significant future pipeline projects for which we have customer commitments. In 2021, we expect to invest capital of approximately $295 million in pipeline projects.

Hillabee

The Hillabee Expansion Project involved an expansion of our existing natural gas transmission system from our Station 85 Pooling Point in Choctaw County, Alabama to an interconnection with the Sabal Trail pipeline in Tallapoosa County, Alabama. The project was constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completed in 2017, and it increased capacity by 818 Mdth/d. We placed Phase II into service on May 1, 2020. Together, the first two phases of the project increased capacity by 1,025 Mdth/d.

Northeast Supply Enhancement

The Northeast Supply Enhancement Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. In May 2019, we received approval from the FERC for the project. However, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection were denied in May 2020. We have not refiled our applications for those approvals. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now require impairment. See further discussion in Critical Accounting Estimates.

Southeastern Trail

The Southeastern Trail Project involved an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 Pooling Point in Louisiana. In October 2019, we received approval from the FERC for the project. We placed 150 Mdth/d of capacity under the project into service in November 2020 and an additional 80 Mdth/d in December 2020. The project achieved full in-service on January 1, 2021. In total, the project increased capacity by 296 Mdth/d.

Leidy South

The Leidy South Project involves an expansion of our existing natural gas transmission system and an extension of our system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. In July 2020, we received approval from the FERC for the project. We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and we plan to place the remainder of the project into service as early as the fourth quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.

Regional Energy Access

The Regional Energy Access Expansion involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland. In June 2020, the FERC approved our request to use the FERC’s pre-filing review process for the project. We anticipate filing our certificate application for the project with the FERC in the first quarter of 2021.We plan to place the project into service as early as the fourth quarter of 2023, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity up to 760 Mdth/d.

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RATE MATTERS

FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and accepted by the FERC before any changes can go into effect. We establish our rates primarily through the FERC's ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariff and FERC policy. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes, and (3) contract and volume throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues may be collected subject to refund. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks.

Since September 1, 1992, we have designed our rates using the straight fixed-variable (SFV) method of rate design. Under the SFV method of rate design, substantially all fixed costs, including return on equity and income taxes, are included in a reservation charge to customers and all variable costs are recovered through a commodity charge to customers. While the use of SFV rate design limits our opportunity to earn incremental revenues through increased throughput, it also limits our risk associated with fluctuations in throughput.

Notice of Inquiry (Docket No. PL19-4-000). On May 21, 2020, the FERC issued a “Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines” (Policy Statement) in Docket No. PL19-4-000 adopting changes to its policies concerning the calculation of a public utility return on equity (ROE). In this Policy Statement, the FERC revised its ROE policy for natural gas pipelines and oil pipelines to provide that the FERC will determine a pipeline’s ROE by averaging the results of the Discounted Cash Flow model and the Capital Asset Pricing Model, with each weighted equally. The FERC declined to adopt any additional policy changes at this time and will address all other issues concerning the determination of a pipeline’s ROE as they arise in future proceedings.

REGULATION

FERC Regulation.

Our interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, as amended (NGA), and under the Natural Gas Policy Act of 1978, as amended, and as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and accounting, among other things, are subject to regulation. We hold certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of pipelines, facilities and properties for which certificates are required under the NGA. The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting gas marketing functions by requiring the employees of a transmission provider that perform transmission functions to function independently from gas marketing employees and by restricting the information that transmission providers may provide to gas marketing employees. Under the Energy Policy Act of 2005, the FERC is authorized to impose civil penalties of up to approximately $1.3 million per day for each violation of its rules.

Environmental Matters.

Our operations are subject to federal environmental laws and regulations as well as the state and local laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:

•Leakage from gathering systems, underground gas storage caverns, pipelines, transportation facilities and storage tanks;

•Damage to facilities resulting from accidents during normal operations;

•Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters; and

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•Blowouts, cratering and explosions.

In addition, we may be liable for environmental damage caused by former owners or operators of our properties.

We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings or current competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.

For additional information regarding the potential impact of federal, state or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors – Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures that could exceed our expectations,” and “Environmental Matters” in Note 4. Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements.

Safety and Maintenance.

Our operations are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 which regulate safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.

Federal pipeline safety laws authorize PHMSA to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. PHMSA has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.

In 2016, PHMSA published a proposed rulemaking that would impose new or more stringent requirements for certain natural gas pipelines including, expanding certain of PHMSA’s current regulatory safety programs for natural gas lines in high-population areas (also known as moderate consequence areas (MCAs)) that do not qualify as high consequence areas (HCAs) and requiring maximum allowable operating pressure (MAOP) validation through re-verification of all historical records for pipelines in service, which may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested. However, PHMSA has since decided to split this proposed rule (Mega Rule), into three separate rulemaking proceedings. The first of these three rulemakings, relating to onshore gas transmission pipelines, was published as a final rule on October 1, 2019, and imposes numerous requirements, including MAOP reconfirmation, the periodic assessment of additional pipeline mileage outside of HCAs, the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integrity management. In accordance with the final rule, we have developed new procedures and updated our existing Pipeline Safety Program to facilitate meeting all requirements within the time frames stated. The remaining rulemakings comprising the Mega Rule are expected to be issued in 2021 and will include revised pipeline repair criteria as well as more stringent corrosion control requirements.

We are also expecting additional regulations due to new pipeline safety legislation finalized in December 2020 that reauthorized PHMSA pipeline safety programs. The new legislation includes mandates for PHMSA to publish final rules for advanced leak detection for gas pipelines, additional repair criteria for gas pipelines, and updated operation and maintenance standards requirements applicable to large-scale liquefied natural gas facilities.

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New regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.

Pipeline Integrity Regulations We have an enterprise-wide Gas Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Plan includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas as defined by the rule. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. We estimate that the cost to be incurred in 2021 associated with this program will be approximately $73 million. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

                    EMPLOYEES

Transco has no employees. Operations, management and certain administrative services are provided by Williams and its affiliates.

                TRANSACTIONS WITH AFFILIATES

We engage in transactions with Williams and other Williams’ subsidiaries. (See Note 1. Summary of Significant Accounting Policies and Note 9. Transactions with Major Customers and Affiliates of Notes to Consolidated Financial Statements.)

Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS

The reports, filings, and other public announcements of Transcontinental Gas Pipe Line Company, LLC, may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters.

All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

•Our and our affiliates’ future credit ratings;

•Amounts and nature of future capital expenditures;

•Expansion and growth of our business and operations;

•Expected in-service dates for capital projects;

•Financial condition and liquidity;

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•Business strategy;

•Cash flow from operations or results of operations;

•Rate case filings;

•Natural gas prices, supply, and demand;

•Demand for our services; and

•The impact of the coronavirus (COVID-19) pandemic.

Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

•The impact of operational and developmental hazards and unforeseen interruptions;

•Development and rate of adoption of alternative energy sources;

•The strength and financial resources of our competitors and the effects of competition;

•Availability of supplies, including lower than anticipated volumes from third parties, and market demand;

•Volatility of pricing including the effect of lower than anticipated energy commodity prices;

•Changes in maintenance and construction costs, as well as our ability to obtain sufficient construction-related inputs, including skilled labor;

•The impact of existing and future laws and regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;

•Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;

•The physical and financial risks associated with climate change;

•Our exposure to the credit risk of our customers and counterparties;

•Our ability to successfully expand our facilities and operations;

•Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;

•Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;

•Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);

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•Our costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;

•The risks resulting from outbreaks or other public health crises, including COVID-19;

•Changes in the current geopolitical situation;

•Changes in U.S. governmental administration and policies;

•Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;

•Acts of terrorism, cybersecurity incidents, and related disruptions; and

•Additional risks described in our filings with the Securities and Exchange Commission (SEC).

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.

RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this report. If any of the risks discussed below occur, our business, prospects, financial condition, results of operations, cash flows and, in some cases our reputation, could be materially adversely affected. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.

Risks Inherent to Our Industry and Business

Our natural gas transportation and storage activities involve numerous risks and hazards that might result in accidents and unforeseen interruptions.

Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural gas including, but not limited to:

•Aging infrastructure and mechanical problems;

•Damages to pipelines and pipeline blockages or other pipeline interruptions;

•Uncontrolled releases of natural gas;

•Operator error;

•Damage caused by third party activity, such as operation of construction equipment;

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•Pollution and other environmental risks; and

•Fires, blowouts, cratering, and explosions.

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage, and substantial losses to us. The location of certain segments of our pipeline in or near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could cause considerable harm and have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.

Certain of our services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

We provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues we collect for our services. Although other services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.

We may not be able to extend or replace expiring natural gas transportation and storage contracts at favorable rates, on a long-term basis, or at all.

Our primary exposure to market risk occurs at the time the terms of existing transportation and storage contracts expire or are subject to termination. Upon expiration or termination of our existing contracts, we may not be able to extend such contracts with existing customers or obtain replacement contracts at favorable rates, on a long-term basis or at all. Failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations, and cash flows. Our ability to extend or replace existing customer contracts on favorable terms is subject to a number of factors, some of which are beyond our control, including:

•The level of existing and new competition to deliver natural gas to our markets and competition from alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy;

•Pricing, demand, availability, and margins for natural gas in our markets;

•Whether the market will continue to support long-term firm contracts;

•The effects of regulation on us, our customers, and our contracting practices; and

•The ability to understand our customers’ expectations, efficiently and reliably deliver high quality services, and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.

Competitive pressures could lead to decreases in the volume of natural gas contracted for or transported through our pipeline system.

The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility, and reliability. Although most of our pipeline system’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the interstate natural gas pipeline industry that have led to increased competition throughout the industry. Similarly, a highly liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is

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being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity.

We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, Williams and its other affiliates may not be limited in their ability to compete with us. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers. We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve, which, if the proposed projects proceed, could increase the competitive pressure upon us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils, and other alternative energy sources. We may not be able to successfully compete against current and future competitors and any failure to do so could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Any significant decrease in supplies of natural gas in the supply basins we access or in demand for those supplies in the markets we serve could adversely affect our business and operating results.

Our ability to maintain and expand our business depends on the level of drilling and production by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves underlying such wells and supply basins with access to our pipeline. Accordingly, we do not have independent estimates of total reserves dedicated to our pipeline or the anticipated life of such reserves. In addition, low prices for natural gas, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transportation, and import and export of natural gas supplies. Localized low natural gas prices in one or more of our existing supply basins, whether caused by a lack of infrastructure or otherwise, could also result in depressed natural gas production in such basins and limit the supply of natural gas made available to us. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers.

Demand for our transportation services depends on the ability and willingness of shippers with access to our facilities to satisfy demand in the markets we serve by deliveries through our system. Any decrease in this demand could adversely affect our business. Demand for natural gas is also affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, and technological advances in fuel economy and energy generation devices, all of which are matters beyond our control.

A failure to obtain sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Significant prolonged changes in natural gas prices could affect supply and demand and cause a reduction in or termination of our long-term transportation and storage contracts or throughput on our system.

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Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in our long-term transportation and storage contracts or throughput on our system. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas, resulting in reduced contracts or throughput on our system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our costs of testing, maintaining, or repairing our facilities may exceed our expectations, and the FERC may not allow, or competition in our markets may prevent, our recovery of such costs in the rates we charge for our services.

We have experienced and could experience in the future unexpected leaks or ruptures on our gas pipeline system or storage facilities. Either as a preventative measure or in response to a leak or another issue, we could be required by regulatory authorities to test or undertake modifications to our systems. If the cost of testing, maintaining, or repairing our facilities exceed expectations and the FERC does not allow us to recover, or competition in our markets prevents us from recovering, such costs in the rates that we charge for our services, such costs could have a material adverse impact on our business, financial condition, results of operations, and cash flows.

The operation of our businesses might be adversely affected by regulatory proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.

Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations, and court proceedings, including litigation of energy industry matters. Both the customers on our system and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations, and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of these ongoing inquiries, investigations, and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals, and similar matters, might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

In addition, existing regulations, including those pertaining to financial assurances to be provided by our businesses in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted, or otherwise enforced in a manner that differs from prior regulatory action. New laws and regulations might also be adopted or become applicable to us, our customers, or our business activities. The change in the U.S. governmental administration and its policies may increase the likelihood of such legal and regulatory developments. If new laws or regulations are imposed relating to oil and gas extraction, or if additional or revised levels of reporting, regulation, or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas that we transport could decline, our compliance costs could increase, and our results of operations could be adversely affected.

Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.

Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social, and governance (“ESG”) practices. Investor advocacy groups, certain institutional investors, investment funds, and other influential investors are also increasingly focused on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. Regardless of the industry, investors’

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increased focus and activism related to ESG and similar matters may hinder access to capital, as investors may decide to reallocate capital or to not commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

We face pressures from our stakeholders, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability. Our stakeholders may require us to implement ESG procedures or standards in order to continue engaging with us, to remain invested in us, or before they will make further investments in us. Additionally, we may face reputational challenges in the event our ESG procedures or standards do not meet the standards set by certain constituencies. We have adopted certain practices as highlighted in Williams’ 2018 Sustainability Report, including with respect to air emissions, biodiversity and land use, climate change, and environmental stewardship. It is possible, however, that our stakeholders might not be satisfied with our sustainability efforts or the speed of their adoption. If we do not meet our stakeholders’ expectations, our business and/or our ability to access capital could be harmed.

Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environment, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change, and investors’ expectations regarding ESG matters, may also adversely affect demand for our services. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business.

The occurrence of any of the foregoing could have a material adverse effect on our business and financial condition.

We may be subject to physical and financial risks associated with climate change.

The threat of global climate change may create physical and financial risks to our business. Energy needs vary with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks.

Additionally, many climate models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions.

To the extent financial markets view climate change and greenhouse gas (“GHG”) emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services. Our business could also be affected by the potential for lawsuits against GHG emitters, based on links drawn between GHG emissions and climate change.

Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations.

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Our operations are subject to extensive federal, state, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, and storage of natural gas as well as waste disposal practices and construction activities. New or amended environmental laws and regulations can also result in significant increases in capital costs we incur to comply with such laws and regulations. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays or denials in granting permits.

Joint and several strict liability may be incurred without regard to fault under certain environmental laws and regulations for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil, and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline system passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest, or alter the operation of those facilities, which might cause us to incur losses.

In addition, climate change regulations and the costs that may be associated with such regulations and with the regulation of emissions of GHGs have the potential to affect our business. Regulatory actions by the U.S. Environmental Protection Agency or the passage of new climate change laws or regulations could result in increased costs to operate and maintain our facilities, install new emissions controls on our facilities, or administer and manage any GHG emissions program. We believe it is possible that future governmental legislation and/or regulation may require us either to limit GHG emissions associated with our operations or to purchase allowances for such emissions. However, we cannot predict precisely what form these future regulations might take, the stringency of any such regulations or when they might become effective. Several legislative bills have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of GHGs that can be emitted (so called “caps”) together with systems of permitted emissions allowances. These proposals could require us to reduce emissions or to purchase allowances for such emissions.

In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that may be adopted. Future legislation and/or regulation designed to reduce GHG emissions could make some of our activities uneconomic to maintain or operate. We continue to monitor legislative and regulatory developments in this area and otherwise take efforts to limit and reduce GHG emissions from our facilities. Although the regulation of GHG emissions may have a material impact on our operations and rates, we believe it is premature to attempt to quantify the potential costs of the impacts.

If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition.    

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We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in our business.

We rely on a limited number of customers for a significant portion of our revenues. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, or at all. For the year ended December 31, 2020, our largest customer was Dominion Energy, Inc., which accounted for approximately 10.0 percent of our operating revenues. The loss of all, or even a portion of, the revenues from contracted volumes supplied by our key customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts, or otherwise, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

We are exposed to the credit risk of our customers and counterparties and our credit risk management will not be able to completely eliminate such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, are required to make pre-payments or provide security to satisfy credit concerns, or are dependent upon us, in some cases without a readily available alternative, to provide necessary services. However, our credit procedures and policies cannot completely eliminate customer credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. In a low commodity price environment certain of our customers have been or could be negatively impacted, causing them significant economic stress resulting, in some cases, in a customer bankruptcy filing or an effort to renegotiate our contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with such customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or, if we so agree, may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection, or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, results of operations, cash flows, and financial condition. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, or otherwise do not take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness, and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

If third-party pipelines and other facilities interconnected to our pipeline and facilities become unavailable to transport natural gas, our revenues could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and storage facilities for the benefit of our customers. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities, or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas to end use markets, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnection causing a material reduction in volumes transported on our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

We do not own all of the land on which our pipeline and facilities are located, which could disrupt our operations.

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We do not own all of the land on which our pipeline and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of any of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.

We have experienced, and we anticipate that we will continue to face, opposition to the operation and expansion of our pipelines and facilities from governmental officials, environmental groups, landowners, tribal groups, local groups, and other advocates. In some instances, we encounter opposition that disfavors hydrocarbon-based energy supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt, or delay the operation or expansion of our assets and business. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property, or the environment or lead to extended interruptions of our operations. Any such event that delays or prevents the expansion of our business, that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could adversely affect our financial condition and results of operations.

We may not be able to grow or effectively manage our growth.

As part of our growth strategy, we engage in significant capital projects. We have a project lifecycle process and an investment evaluation process. These are processes we use to identify, evaluate, and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing, or treating pipelines and facilities, as well as the expansion of existing facilities. Additional risks associated with construction may include the inability to obtain rights-of-way, skilled labor, equipment, materials, permits, and other required inputs in a timely manner such that projects are completed on time and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:

•Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes that are materially different than anticipated;

•We could be required to contribute additional capital to support acquired businesses or assets and we may assume liabilities that were not disclosed to us that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;

•Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations, and make it difficult to maintain our current business standards, controls, and procedures; and

•Acquisitions and capital projects may require substantial new capital, including the issuance of debt or equity, and we may not be able to access credit or capital markets or obtain acceptable terms.

If realized, any of these risks could have an adverse impact on our financial condition, results of operations, including the possible impairment of our assets, or cash flows.

Risks Related to Strategy and Financing

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A downgrade of our credit ratings, which are determined outside of our control by independent third parties, could impact our liquidity, access to capital, and our costs of doing business.

Downgrades of our credit ratings increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could be limited by a downgrade of our credit ratings.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria such as business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the credit ratings agencies.

Our ability to obtain credit in the future could be affected by Williams’ credit ratings.

Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans, dividends, and distributions paid to it by its subsidiaries. Due to our relationship with Williams, our ability to obtain credit will be affected by Williams’ credit ratings. If Williams were to experience a deterioration in its credit standing or financial condition, our access to capital and our ratings could be adversely affected. Any downgrading of a Williams credit rating could result in a downgrading of our credit rating. A downgrading of a Williams credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.

Our total outstanding long-term debt (including current portion) as of December 31, 2020 was $5.24 billion.

The agreements governing our indebtedness contain covenants that restrict our ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to guarantee certain indebtedness, to make certain distributions during the continuation of an event of default, and to enter into certain affiliate transactions and certain restrictive agreements and to change the nature of our business. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Williams’ debt agreements contain similar covenants with respect to Williams and its subsidiaries, including us.

Our debt service obligations and the covenants described above could have important consequences. For example, they could, among other things:

•Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;

•Impair our ability to obtain additional financing in the future for working capital, capital expenditures, general limited liability company purposes, or other purposes;

•Diminish our ability to withstand a continued or future downturn in our business or the economy generally;

•Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, general limited liability company purposes, or other purposes; and

•Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including by limiting our ability to expand or pursue our business activities and by preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.

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Our ability to comply with our debt covenants, to repay, extend, or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations, or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital, or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity”.

Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.

Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are industrial or economic contraction (including as a result of the COVID-19 pandemic) leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. We, along with Williams and Northwest Pipeline LLC, are party to a credit agreement with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. We and Northwest Pipeline LLC are each subject to a $500 million borrowing sublimit. As of December 31, 2020, we had a borrowing capacity of $500 million under such credit facility, but our ability to borrow under that facility could be impaired if one or more of our lenders fails to honor its contractual obligation to lend to us. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manner described above.

Williams can exercise substantial control over our distribution policy and our business and operations and may do so in a manner that is adverse to our interests.

Because we are an indirect wholly-owned subsidiary of Williams, Williams exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:

•Payment of distributions and repayment of advances;

•Decisions on financings and our capital raising activities;

•Mergers or other business combinations; and

•Acquisition or disposition of assets.

Williams could decide to increase distributions or advances to our member consistent with existing debt covenants. This could adversely affect our liquidity.

Risks Related to Regulations That Affect Our Industry

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Our natural gas transportation and storage operations are subject to regulation by the FERC, which could have an adverse impact on our ability to establish transportation and storage rates that would allow us to recover the full cost of operating our pipeline and storage assets, including a reasonable rate of return.

In addition to regulation by other federal, state, and local regulatory authorities, under the NGA, our interstate pipeline transportation and storage services and related assets are subject to regulation by the FERC. Federal regulation extends to such matters as:

•Transportation of natural gas in interstate commerce;

•Rates, operating terms, types of services and conditions of service;

•Certification and construction of new interstate pipeline and storage facilities;

•Acquisition, extension, disposition, or abandonment of existing interstate pipeline and storage facilities;

•Accounts and records;

•Depreciation and amortization policies;

•Relationships with affiliated companies that are involved in marketing functions of the natural gas business; and

•Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.

Regulatory or administrative actions in these areas, including successful complaints or protests against our rates, can affect our business in many ways, including by decreasing existing tariff rates or setting future tariff rates to levels such that revenues are inadequate to recover increases in operating costs or to sustain an adequate return on capital investments, decreasing volumes in our pipelines, increasing our costs, and otherwise altering the profitability of our business.

Unlike other interstate pipelines that own facilities in the offshore Gulf of Mexico, we charge our transportation customers a separate fee to access our offshore facilities. The separate charge is referred to as an “IT feeder” charge. The “IT feeder” rate is charged only when gas is actually transported on the applicable facilities and typically it is paid by producers or marketers. Because the “IT feeder” rate is typically paid by producers and marketers, it generally results in netback prices to producers that are slightly lower than the netbacks realized by producers transporting on other interstate pipelines. This rate design disparity can result in producers bypassing our offshore facilities in favor of alternative transportation facilities.

Risks Related to Employees and Outsourcing of Support Activities

Failure of our service providers or disruptions to outsourcing relationships might negatively impact our ability to conduct our business.

We rely on Williams and other third parties for certain services necessary for us to be able to conduct our business. We have a limited ability to control these operations and the associated costs. Certain of Williams’ accounting and information technology functions that we rely on are currently provided by third party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these arrangements could be disrupted. Similarly, the expiration of agreements associated with such arrangements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our allocation from Williams for costs for its defined benefit pension plans and other postretirement benefit plans are affected by factors beyond our and Williams’ control.

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As we have no employees, employees of Williams and its affiliates provide services to us. As a result, we are allocated a portion of Williams’ costs for defined benefit pension plans and other postretirement benefit plans. The timing and amount of our allocations under the defined benefit pension plans depend upon a number of factors that Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates, and changes in pension laws. Changes to these and other factors that can significantly increase our allocations could have a significant adverse effect on our results of operations and financial condition.

Risks Related to Weather, Other Natural Phenomena and Business Disruption

We face risks related to the COVID-19 pandemic and other health epidemics.

The global outbreak of COVID-19 is currently impacting countries, communities, supply chains, and markets. We provide a critical service to our customers, which means that it is paramount that we keep our employees safe. To date, COVID-19 has not had a material impact on our business. However, we cannot predict whether, and the extent to which, COVID-19 will have a material impact on our business, including our liquidity, financial condition, and results of operations. COVID-19 could pose a risk to our employees, our customers, our suppliers, and the communities in which we operate, which could negatively impact our business. To the extent that our access to the capital markets is adversely affected by COVID-19, we may need to consider alternative sources of funding for our operations and for working capital, any of which could increase our cost of capital. Measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter in place orders, and shutdowns, may cause us to experience operational delays or to delay plans for growth. The extent to which COVID-19 may impact our business will depend on future developments, which are highly uncertain and cannot be predicted, including new information concerning the severity of COVID-19 and the actions taken to contain it or treat its impact, among others.

To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other factors described in this report.

Our assets and operations, as well as our customers’ assets and operations, can be affected by weather and other natural phenomena.

Our assets and operations, especially those located offshore, and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or the occurrence of a significant liability for which we were not fully insured could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our business could be negatively impacted by acts of terrorism and related disruptions.

Given the volatile nature of the commodities we transport and store, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets, or cause significant harm to our operations, such as full or partial disruption to our ability to transport natural gas. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.

We rely on our information technology infrastructure to process, transmit, and store electronic information, including information we use to safely operate our assets. In addition to the oversight of our business provided by our Management Committee, the Williams’ Board of Directors has oversight responsibility with regard to enterprise-wide assessment of the major risks inherent in its businesses, including cybersecurity risks. Accordingly, the Williams’ Board of Directors reviews management’s efforts to address and mitigate such risks, including the

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establishment and implementation of policies to address cybersecurity threats. We have invested, and expect to continue to invest, significant time, manpower, and capital in our information technology infrastructure. However, the age, operating systems, or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. While we believe that we maintain appropriate information security policies, practices, and protocols, we regularly face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants, and assets. We face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists”, or private individuals. We face the threat of theft and misuse of sensitive data and information, including customer and employee information. We also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information. We also are subject to cybersecurity risks arising from the fact that our business operations are interconnected with third parties, including third-party pipelines, other facilities, and our contractors and vendors. In addition, the breach of certain business systems could affect our ability to correctly record, process, and report financial information. Breaches in our information technology infrastructure or physical facilities, or other disruptions, including those arising from theft, vandalism, fraud, or unethical conduct, could result in damage to or destruction of our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability, the loss of contracts, the imposition of significant costs associated with remediation and litigation, heightened regulatory scrutiny, increased insurance costs, and have a material adverse effect on our operations, financial condition, results of operations, and cash flows.

General Risk Factors

We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.

In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, and cash flows, and our ability to repay our debt.

A failure to attract and retain an appropriately qualified workforce could negatively impact our results of operations.

Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with projects and ongoing operations. Williams’ failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor, may adversely affect our ability to manage and operate the businesses. If Williams is unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across real property owned by others. Compressor stations, with appurtenant facilities, are located in whole or in part either on lands owned or on sites held under leases or permits issued or approved by public authorities. Our storage facilities are either owned or contracted for under long-term leases or easements. We lease our company offices in Houston, Texas.

21

Item 3. Legal Proceedings

Environmental

While it is not possible for us to predict the final outcome of any pending legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment, we do not anticipate a material effect on our consolidated financial position if we were to receive an unfavorable outcome in any one or more of such proceedings. Our threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million.

Other

The additional information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements – Note 4. Contingent Liabilities and Commitments”.

Item 4. Mine Safety Disclosures

Not applicable.

22

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

We are indirectly owned by Williams.

Distributions totaling $1,020 million were declared and paid by us to our parent during the year ended December 31, 2020. Distributions totaling $824 million were declared and paid by us to our parent during the year ended December 31, 2019.

In the year ended December 31, 2020, our parent made contributions totaling $115 million to us. During February 2021, our parent made an additional $60 million contribution to us.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

The following discussion and analysis of critical accounting estimates, results of operations and capital resources and liquidity should be read in conjunction with the financial statements and notes thereto included within Item 8.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions.  We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

Property, Plant, and Equipment

We evaluate our long-lived assets, including capitalized project development costs, for impairment when events or changes in circumstances indicate, in our management's judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred, we compare our management's estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred.

We evaluated $212 million of capitalized project development costs for the Northeast Supply Enhancement project for impairment as of December 31, 2020. As previously discussed, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project.

Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now require impairment. The estimated fair value of the materials within capitalized project costs was determined to be $42 million and considered other internal uses and estimated salvage values. The remaining capitalized costs were determined to have no fair value. As a result, we recognized an impairment charge of $170 million during the fourth quarter of 2020. Our assumption regarding the probability of completing the project is subjective and required management to exercise significant judgment. The use of an alternate judgment could have resulted in a different conclusion regarding the need to evaluate the project for impairment.

Regulatory Accounting

We are regulated by the FERC. Accounting Standards Codification (ASC) Topic 980, Regulated Operations, (Topic 980) provides that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits

23

that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management's expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. We record certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and included in the Consolidated Statement of Comprehensive Income for the period in which the discontinuance of regulatory accounting treatment occurs, unless otherwise required to be recorded under other provisions of U.S. generally accepted accounting principles. The aggregate amount of regulatory assets reflected in the Consolidated Balance Sheet is $344.7 million at December 31, 2020. The aggregate amount of regulatory liabilities reflected in the Consolidated Balance Sheet is $1,003.9 million at December 31, 2020. A summary of regulatory assets and liabilities is included in Note 11. Regulatory Assets and Liabilities of Notes to Consolidated Financial Statements.

Results of Operations

Analysis of Financial Results

This analysis discusses financial results of our operations for the years 2020 and 2019. Variances due to changes in natural gas prices and transportation volumes have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.

We have cash out sales, which settle gas imbalances with shippers. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems, which may deliver different quantities of gas on our behalf than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables. Our tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on our operating income.

2020 COMPARED TO 2019

Operating Income and Net Income

Operating Income for 2020 was $1,170.2 million compared to $1,205.0 million for 2019. The decrease in Operating Income of $34.8 million (2.9 percent) was due to an increase in Operating Costs and Expenses, in 2020 compared to 2019, as discussed below. Net Income for 2020 was $880.0 million compared to $963.3 million for 2019. The decrease in Net Income of $83.3 million (8.6 percent) was mostly attributable to an increase in Operating Costs and Expenses, partially offset by an increase in Operating Revenues, as discussed below.

Operating Revenues

Natural gas sales decreased $25.5 million (24.1 percent) to $80.4 million for 2020 when compared to 2019. The decrease was due to lower cash-out sales.

24

Natural gas transportation for 2020 was $2,241.8 million compared to $2,188.1 million for 2019. The $53.7 million (2.5 percent) increase was primarily attributable to:

•$16.5 million from our Gateway project placed into service in December 2019;

•$16.1 million from our Hillabee Phase 2 project placed in service in May 2020;

•$16.0 million from our Rivervale South project placed in service in September 2019;

•$3.9 million from our Southeastern Trail project placed in service in November 2020;

•$2.0 million from our Leidy South project partially placed in service in November 2020; and

•$2.8 million from a combination of higher electric power costs, St. James project placed into service April 2019, and seasonal services.

•Partially offset by $3.6 million lower commodity revenue.

Natural gas storage increased $14.3 million (9.7 percent) for 2020 compared to 2019. The increase was primarily due to higher revenues from storage services and higher commodity and demand storage revenue.

Other for 2020 increased $9.1 million (82.2 percent) compared to 2019 primarily due to $9.2 million higher park and loan activity.

Operating Costs and Expenses

Excluding the Cost of natural gas sales, which is directly offset in revenues, our operating expenses increased approximately $111.9 million (9.8 percent) from the comparable period in 2019. This increase was primarily attributable to:

•$170.1 million (100.0 percent) related to an impairment of assets for the Northeast Supply Enhancement project;

•$30.3 million (7.0 percent) increase in Depreciation and amortization costs due to $15.3 million increase in ARO asset depreciation and $13.5 million increase resulting from additional assets placed in service;

•$7.1 million (9.2 percent) increase in Taxes - other than income taxes primarily due to additional assets placed in service; and

•$3.4 million (6.7 percent) increase in Cost of natural gas transportation costs primarily resulting from $1.2 million higher electric power costs, $1.1 million fuel cost adjustment related to the Docket No. RP18-1126 rate case settlement, and higher fuel expense of $0.8 million. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.

•Partially offset by $59.4 million (15.5 percent) decrease in Operation and maintenance costs primarily resulting from $43.6 million decrease in employee labor and related benefit costs ($15.4 million lower due to lower headcount, $17.6 million lower due to the absence of costs associated with the voluntary separation program and restructuring, and $10.6 million due to employee benefit policy change), $24.9 million decrease in contracted services compared to 2019, partly offset by $10.9 million unfavorable costs related to lower capitalized labor;

•$32.2 million (14.9 percent) decrease in Administrative and general costs primarily due to $13.9 decrease due to costs expensed in 2019 related to FERC audit findings and $19.3 million decrease in employee labor and related benefits costs ($11.0 million related to the absence of costs associated with the voluntary separation program and restructuring, $5.2 million due to employee benefit policy change, and $3.1 million due to lower headcount); and

•$6.6 million (27.1 percent) favorable change in Regulatory credit resulting from tax rate changes primarily related to ten months of amortization in 2019 compared to the twelve months in 2020.

Other (Income) and Other Expenses

Other (Income) and Other Expenses in 2020 had an unfavorable change of $48.5 million (20.1 percent) over 2019. This unfavorable change was primarily attributable to:

25

•A $27.5 million (9.7 percent) unfavorable Interest expense - other primarily due to new debt issued in May 2020. (See Note 5 of Notes to Consolidated Financial Statements);

•A $16.6 million (42.4 percent) unfavorable change in Allowance for equity and borrowed funds used during construction (AFUDC) due to a decrease in capital spending;

•A $3.2 million (100.0 percent) unfavorable Equity in (earnings) losses of unconsolidated affiliates due to the distribution of investments in our subsidiaries to our parent in December 2019.

CAPITAL RESOURCES AND LIQUIDITY

Method of Financing

We fund our capital requirements with cash flows from operating activities, equity contributions from Williams, advances from Williams, accessing capital markets, and, if required, borrowings under the credit facility described below.

We may raise capital through private debt offerings, as well as offerings registered pursuant to offering-specific registration statements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. On May 8, 2020, we completed a private placement of $700 million of 3.25 percent senior unsecured notes due 2030 and $500 million of 3.95 percent senior unsecured notes due 2050. We used the net proceeds from the offering for general corporate purposes, including the funding of capital expenditures. The notes issued in May 8, 2020 were the subject of a registration rights agreement. In the fourth quarter of 2020, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act.

We, along with Williams and Northwest Pipeline LLC, are co-borrowers under a $4.5 billion unsecured credit facility. Total letter of credit capacity available to Williams under the credit facility is $1.0 billion. We may borrow up to $500 million under the credit facility to the extent not otherwise utilized by Williams and Northwest Pipeline LLC. See Note 5 of Notes to Consolidated Financial Statements for further discussion of the credit facility.

We are a participant in Williams's cash management program, and we make advances to and receive advances from Williams. At December 31, 2020, our advances to Williams totaled approximately $642.7 million. At December 31, 2019, our advances from Williams totaled approximately $252.5 million. These advances are represented by demand notes.

Capital Expenditures

We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. We anticipate 2021 capital expenditures will be approximately $295 million for expansion projects and $237 million for maintenance projects.

Recent Developments

COVID-19

The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We are monitoring the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. We are continuing to monitor developments with respect to the outbreak and note the following:

26

•Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.

•We believe we have the ability to access the debt market if necessary, and continue to have significant levels of unused capacity on our revolving credit facility with no significant debt maturities in the near future.

•We continue to monitor and adapt our remote working arrangements and limit business-related travel. Implementation of these measures has not required material expenditures or significantly impacted our ability to operate our business.

•Our remote working arrangements have not significantly impacted our internal controls over financial reporting and disclosure controls and procedures.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

At December 31, 2020, our debt portfolio included only fixed rate issues. The following table provides information about our long-term debt, including current maturities, as of December 31, 2020. The table presents principal cash flows and weighted-average interest rates by expected maturity dates.

December 31, 2020	Expected Maturity Date
	2021			2022			2023			2024
	(Dollars in millions)
Long-term debt, excluding other financing obligation:
Fixed rate	$	—		$	—		$	—		$	—
Interest rate	5.20		%	5.20		%	5.20		%	5.20		%
Other financing obligation:
Fixed rate	$	23		$	25		$	27		$	30
Interest rate	9.01		%	9.01		%	9.01		%	9.01		%
December 31, 2020	Expected Maturity Date
	2025			Thereafter			Total			Fair Value
	(Dollars in millions)
Long-term debt, excluding other financing obligation:
Fixed rate	$	—		$	4,183		$	4,183		$	5,074
Interest rate	5.20		%	4.41		%
Other financing obligation:
Fixed rate	$	32		$	967		$	1,104		$	1,875
Interest rate	9.01		%	9.04		%

27

Item 8. Financial Statements and Supplementary Data

	Page
Report of Independent Registered Public Accounting Firm	29
Consolidated Statement of Comprehensive Income	31
Consolidated Balance Sheet	32
Consolidated Statement of Member’s Equity	34
Consolidated Statement of Cash Flows	35
Notes to Consolidated Financial Statements	37

28

Report of Independent Registered Public Accounting Firm

To the Management Committee and Member of Transcontinental Gas Pipe Line Company, LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Transcontinental Gas Pipe Line Company, LLC (the Company) as of December 31, 2020 and 2019, the related consolidated statements of comprehensive income, member’s equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

29

Description of the Matter

Regulatory Assets and Liabilities As discussed in Note 1 to the consolidated financial statements, the Company is an interstate natural gas transmission company that is regulated by the Federal Energy Regulatory Commission (“FERC”) and applies accounting principles in Topic 980 for regulated operations. As such, certain incurred costs that would otherwise be charged to expense are deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense are deferred as regulatory liabilities, based on the expected return to customers in future rates. The Company records items as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. Auditing regulatory assets and liabilities is complex as it requires specialized knowledge of rate-regulated activities and judgments as to matters that could affect the recording of regulatory assets and liabilities.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design, and tested the operating effectiveness of internal controls over the Company’s accounting for regulatory assets and liabilities, including, among others, controls over the evaluation of filings with regulatory bodies and their effects on existing regulatory assets and liabilities, including factors that may affect the timing or nature of recoverability. We performed audit procedures that included, among others, reviewing evidence of correspondence with regulatory bodies to test that the Company evaluated new information obtained from regulatory rulings. For example, we assessed the recoverability, considering information obtained from regulatory orders and ongoing proceedings, of various regulatory assets including deferred cash out costs. In addition, we tested calculations of material regulatory assets and liabilities, including that amortization for certain regulatory assets and liabilities corresponded to relevant regulatory rulings and/or orders.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 1995.

Houston, Texas

February 24, 2021

30

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

	Years Ended December 31,
	2020		2019		2018
Operating Revenues:
Natural gas sales	$	80,351	$	105,884	$	127,821
Natural gas transportation	2,241,760		2,188,058		1,784,794
Natural gas storage	161,956		147,687		136,666
Other	20,246		11,113		10,600
Total operating revenues	2,504,313		2,452,742		2,059,881
Operating Costs and Expenses:
Cost of natural gas sales	80,351		105,884		127,821
Cost of natural gas transportation	53,654		50,273		38,749
Operation and maintenance	323,093		382,513		399,293
Administrative and general	184,768		217,000		189,588
Depreciation and amortization	463,757		433,480		366,566
Taxes — other than income taxes	83,687		76,632		67,537
Impairment of assets	170,128		—		—
Regulatory credit resulting from tax rate changes	(30,752)		(24,202)		(20,867)
Other expense, net	5,461		6,195		64,918
Total operating costs and expenses	1,334,147		1,247,775		1,233,605
Operating Income	1,170,166		1,204,967		826,276
Other (Income) and Other Expenses:
Interest expense - affiliate	892		2,319		60
- other	311,451		283,990		218,126
Interest income - affiliate	(132)		(89)		(7,606)
- other	(4,265)		(4,349)		(3,448)
Allowance for equity and borrowed funds used during construction (AFUDC)	(22,648)		(39,289)		(116,347)
Equity in earnings of unconsolidated affiliates	—		(3,216)		(1,068)
Miscellaneous other (income) expenses, net	4,832		2,305		(4,520)
Total other (income) and other expenses	290,130		241,671		85,197
Net Income	880,036		963,296		741,079
Other comprehensive income:
Equity interest in unrealized gain on interest rate hedges (includes $(162) and $(143) for the years ended December 31, 2019 and 2018, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges)	—		(641)		197
Comprehensive Income	$	880,036	$	962,655	$	741,276

See accompanying notes.

31

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

	December 31,
	2020		2019
ASSETS
Current Assets:
Cash	$	—	$	—
Receivables:
Trade	223,864		242,416
Affiliates	1,011		669
Advances to affiliate	642,734		—
Other	14,660		10,850
Transportation and exchange gas receivables	4,627		6,360
Inventories:
Gas in storage, at original cost	926		857
Gas available for customer nomination, at average cost	7,909		20,653
Materials and supplies, at average cost	47,462		43,482
Regulatory assets	62,861		69,440
Other	13,847		11,240
Total current assets	1,019,901		405,967
Property, Plant and Equipment:
Natural gas transmission plant	17,123,779		16,764,904
Less-Accumulated depreciation and amortization	4,802,256		4,438,077
Total property, plant and equipment, net	12,321,523		12,326,827
Other Assets:
Regulatory assets	281,870		290,923
Right-of-use assets	78,899		84,979
Other	252,051		210,017
Total other assets	612,820		585,919
Total assets	$	13,954,244	$	13,318,713

(continued)

See accompanying notes.

32

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

	December 31,
	2020		2019
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Payables:
Trade	$	109,636	$	155,676
Affiliates	32,676		47,740
Advances from affiliate	—		252,549
Cash overdrafts	18,813		28,292
Transportation and exchange gas payables	1,905		3,961
Reserve for rate refunds	—		188,842
Accrued liabilities:
Property and other taxes	20,177		19,034
Interest	75,806		70,572
Regulatory liabilities	57,086		57,359
Customer deposits	24,686		30,551
Customer advances	27,082		27,207
Asset retirement obligations	52,764		32,704
Other	41,864		19,060
Long-term debt due within one year	22,640		20,180
Total current liabilities	485,135		953,727
Long-Term Debt	5,217,140		4,044,790
Other Long-Term Liabilities:
Asset retirement obligations	397,737		426,505
Regulatory liabilities	946,774		966,961
Advances for construction costs	38,585		16,533
Deferred revenue	205,030		215,598
Lease liability	78,688		84,528
Other	4,336		4,288
Total other long-term liabilities	1,671,150		1,714,413
Contingent Liabilities and Commitments (Note 4)
Member’s Equity:
Member’s capital	4,543,499		4,428,499
Retained earnings	2,037,320		2,177,284
Total member’s equity	6,580,819		6,605,783
Total liabilities and member’s equity	$	13,954,244	$	13,318,713

See accompanying notes.

33

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF MEMBER’S EQUITY

(Thousands of Dollars)

	Years Ended December 31,
	2020		2019		2018
Member's Capital:
Balance at beginning of period	$	4,428,499	$	4,428,499	$	4,088,499
Cash contributions from parent	115,000		—		340,000
Balance at end of period	4,543,499		4,428,499		4,428,499
Retained Earnings:
Balance at beginning of period	2,177,284		2,099,567		1,848,488
Net income	880,036		963,296		741,079
Cash distributions to parent	(1,020,000)		(824,000)		(490,000)
Non-cash distribution to parent	—		(25,000)		—
Non-cash distribution of investments in subsidiaries	—		(36,579)		—
Balance at end of period	2,037,320		2,177,284		2,099,567
Accumulated Other Comprehensive Income:
Balance at beginning of period	—		534		337
Equity interest in unrealized gain (loss) on interest rate hedge	—		(641)		197
Non-cash distribution of investments in subsidiaries	—		107		—
Balance at end of period	—		—		534
Total Member's Equity	$	6,580,819	$	6,605,783	$	6,528,600

See accompanying notes.

34

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

	Years Ended December 31,
	2020		2019		2018
Cash flows from operating activities:
Net income	$	880,036	$	963,296	$	741,079
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	463,757		433,480		366,566
Impairment of assets	170,128		—		—
Allowance for equity funds used during construction (equity AFUDC)	(14,889)		(28,785)		(87,111)
Regulatory credit resulting from tax rate changes	(30,752)		(24,202)		(20,867)
Equity in earnings of unconsolidated affiliates	—		(3,216)		(1,068)
Distributions from unconsolidated affiliates	—		4,908		3,250
Changes in operating assets and liabilities:
Receivables — affiliates	(342)		582		91
— trade and other	14,742		(52,307)		(30,776)
Transportation and exchange gas receivable	1,733		(1,845)		(1,310)
Regulatory assets - current	6,579		26,330		1,379
Regulatory assets - non-current	11,361		3,622		(8,605)
Inventories	8,695		(1,787)		(23,178)
Payables — affiliates	(15,064)		(2,981)		7,307
— trade	(915)		(18,842)		(35,869)
Accrued liabilities	22,881		(1,723)		40,993
Asset retirement obligations	12,027		15,713		24,659
Reserve for rate refunds	(188,842)		188,842		—
Deferred revenue	(10,568)		(10,566)		(10,565)
Other, net	(36,990)		(36,365)		10,317
Net cash provided by operating activities	1,293,577		1,454,154		976,292
Cash flows from financing activities:
Proceeds from long-term debt	1,195,629		—		993,440
Proceeds from other financing obligations	8,725		41,513		50,269
Retirement of long-term debt	—		—		(250,000)
Payments on other financing obligations	(20,366)		(17,436)		(3,705)
Payments for debt issuance costs	(11,441)		—		(10,148)
Cash distributions to parent	(1,020,000)		(824,000)		(490,000)
Cash contributions from parent	115,000		—		340,000
Advances from affiliate, net	(252,549)		252,549		—
Net cash provided by (used in) financing activities	14,998		(547,374)		629,856

(continued)

See accompanying notes.

35

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

	Years Ended December 31,
	2020		2019		2018
Cash flows from investing activities:
Capital expenditures*	$	(649,459)	$	(901,374)	$	(2,326,672)
Contributions and advances for construction costs	35,284		47,034		408,912
Disposal of property, plant and equipment, net	(43,900)		(45,720)		(26,469)
Advances to affiliate, net	(642,734)		33,034		362,213
Contributions to unconsolidated affiliates	—		(12,250)		—
Purchase of ARO Trust investments	(53,357)		(72,946)		(51,793)
Proceeds from sale of ARO Trust investments	45,591		45,479		27,661
Other, net	—		(37)		—
Net cash used in investing activities	(1,308,575)		(906,780)		(1,606,148)
Increase (decrease) in cash	—		—		—
Cash at beginning of period	—		—		—
Cash at end of period	$	—	$	—	$	—
*   Increase to property, plant and equipment, exclusive of equity AFUDC	$	(582,896)	$	(854,761)	$	(2,085,888)
Changes in related accounts payable and accrued liabilities	(66,563)		(46,613)		(240,784)
Capital expenditures	$	(649,459)	$	(901,374)	$	(2,326,672)
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (exclusive of amount capitalized)	$	299,470	$	268,559	$	168,418
Income taxes	352		76		632

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and, unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.”

Transco was indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which was consolidated by The Williams Companies, Inc. (Williams). On August 10, 2018, Williams completed a merger with WPZ, pursuant to which Williams acquired all of the publicly held outstanding common units of WPZ in exchange for shares of Williams' common stock (WPZ Merger). Williams continued as the surviving entity. Transco is now indirectly owned by Williams.

Transco is a single member limited liability company, and as such, single member losses are limited to the amount of its investment.

Nature of Operations

We are an interstate natural gas transmission company that owns and operates a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania.

Regulatory Accounting

We are regulated by the Federal Energy Regulatory Commission (FERC). Accounting Standards Codification (ASC) Regulated Operations, (Topic 980), provides that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management's expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. We record certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations (ARO), and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements.

Basis of Presentation

Williams’ acquisition of us in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At

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December 31, 2020, the remaining property, plant and equipment allocation was approximately $0.5 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.

Principles of Consolidation

The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments prior to December 31, 2019 (See Note 9) consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $4.9 million and $3.2 million in 2019 and 2018, respectively. We made a $12.3 million contribution to Pine Needle in the second quarter of 2019.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; and 6) asset retirement obligations.

Revenue Recognition

Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators.

Service revenue contracts from our gas pipeline business contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our natural gas sales contracts have a single performance obligation with revenue recognized at a point in time when the natural gas has been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset.

Operating Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual

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commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following:

•Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

•Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Natural Gas Sales

In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).

Contract Liabilities

Our contract liabilities consist of advance payments from customers, which include prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods, and are classified as current or non-current according to when such amounts are expected to be recognized. Current and non-current contract liabilities are included within Accrued Liabilities and Other Long-Term Liabilities - Deferred revenue, respectively, in our Consolidated Balance Sheet.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component.

Leases

We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions. We recognize a

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lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. As an accounting policy, we have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.

We used judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2020, 2019 and 2018 are as follows:

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Category of Property	2020-2019 (1)	2018
Gathering facilities	0% - 1.00%	1.35% - 2.50%
Storage facilities	1.86% -  2.05%	2.10% -  2.25%
Onshore transmission facilities	2.50%  -  7.13%	2.61%  -  5.00%
Offshore transmission facilities	1.25%  -  1.25%	1.20%  -  1.20%

(1)     Changes in depreciation rates in 2019 were due to placing into effect the rates in Docket No. RP18-1126

on March 1, 2019.

We record a liability and increase the basis in the underlying asset for the present value of each expected future Asset Retirement Obligations (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates.

Impairment of Long-lived Assets

We evaluate our long-lived assets, including capitalized project development costs, for impairment when events or changes in circumstances indicate, in our management's judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred, we compare our management's estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

Judgments and assumptions are inherent in our estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize.

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $7.7 million, $10.5 million, and $29.2 million, for 2020, 2019 and 2018, respectively. The allowance for equity funds was $14.9 million, $28.8 million, and $87.1 million, for 2020, 2019 and 2018, respectively.

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Income Taxes

We are a natural gas company organized as a pass-through entity and our taxable income or loss is consolidated on the federal income tax return of our parent, Williams. We generally are treated as a pass-through entity for state and local income tax purposes, and those taxes are generally borne on a consolidated basis by Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We estimate the reserves, considering current expected credit losses (as discussed below in Accounting Standards Issued and Adopted). We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables.

Gas Imbalances

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2020 and 2019. We utilize the average cost method of accounting for gas imbalances.

Deferred Cash Out

Most transportation imbalances are settled in cash on a monthly basis (cash-out). In accordance with our tariff, revenues received from the cash-out of transportation imbalances in excess of costs incurred are deferred and offset by the deferral of costs incurred in excess of revenues received. At the end of each annual August through July reporting period, if the cumulative revenues received exceed the costs incurred, the over recovered amounts are refunded. If the cumulative revenues received are less than the costs incurred, the net under recovered amounts are carried forward and offset against any future net over recoveries that may occur in a subsequent annual reporting period.

Gas Inventory

We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2020 and 2019, Gas in Storage, at LIFO, was zero. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.

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Materials and Supplies Inventory

All inventories are stated at average cost. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2020 and 2019.

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Pension and Other Postretirement Benefits

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 8.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost.

Cash Flows from Operating Activities and Cash Equivalents

We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.

Accounting Standards Issued and Adopted

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changed the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We adopted ASU 2016-13 effective January 1, 2020, which primarily applied to our short-term trade receivables. There was no cumulative effect adjustment to retained earnings upon adoption.

The majority of our trade receivable balances are due within 30 days. We monitor the credit quality of our counterparties through review of collection trends, credit ratings, and other analysis, such as bankruptcy monitoring. Financial assets are evaluated as one pool. Changes in counterparty risk factors could lead to reassessment of the composition of our financial assets as one pool. We calculate our allowance for credit losses incorporating an aging method. In estimating our expected credit losses, we utilized historical loss rates over many years. Our expected credit loss estimate considered both internal and external forward-looking commodity price expectations, as well as counterparty credit ratings, and factors impacting their near-term liquidity.

Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. We do not have a material amount of significantly aged receivables at December 31, 2020.

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2. REVENUE RECOGNITION

Revenue by Category

Our revenue disaggregation by major service line includes Natural gas sales, Natural gas transportation, Natural gas storage, and Other, which are separately presented on the Condensed Consolidated Statement of Comprehensive Income.

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	December 31, 2020		December 31, 2019
	(Thousands)
Balance at beginning of period	$	226,164	$	236,730
Recognized in revenue	(10,568)		(10,566)
Balance at end of period	$	215,596	$	226,164

Remaining Performance Obligations

Our remaining performance obligations primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs, net of estimated reserve for refund, for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. This table excludes the variable consideration component for commodity charges. Certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligation as of December 31, 2020, do not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.

The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2020.

	Contract Liabilities		Remaining Performance Obligations
	(Thousands)
2021	$	10,566	$	2,349,047
2022	10,566		2,196,621
2023	10,566		2,040,685
2024	10,568		1,487,964
2025	10,566		1,453,924
Thereafter	162,764		12,231,530
Total	$	215,596	$	21,759,771

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Accounts Receivable

Receivables from contracts with customers are included within Receivables - Trade and Receivables - Affiliates and receivables that are not related to contracts with customers are included within the balance of Receivables - Advances to affiliate and Receivables - Other in our Consolidated Balance Sheet.

3. LEASES

We are a lessee through non-cancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions.

	Twelve Months Ended   December 31,
	2020			2019
	(Thousands)
Lease Cost:
Operating lease cost	$	9,691		$	10,276
Variable lease cost	3,135			6,867
Total lease cost	$	12,826		$	17,143
Cash paid for amounts included in the measurement of operating lease liabilities	$	3,690		$	9,986
	December 31,
	2020			2019
	(Thousands)
Other Information:
Right-of-use assets	$	78,899		$	84,979
Operating lease liabilities:
Current (included in Accrued liabilities - Other in our Consolidated Balance Sheet)	$	6,222		$	811
Lease liability	$	78,688		$	84,528
Weighted-average remaining lease term - operating leases (years)	15			15
Weighted-average discount rate - operating leases	4.66		%	4.65		%

Prior to adopting ASU 2016-02, total rent expense was $10.8 million in 2018 and primarily included in Operation and maintenance and Administrative and general expenses in the Consolidated Statement of Comprehensive Income.

As of December 31, 2020, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:

	(Thousands)
2021	$	9,471
2022	9,611
2023	9,614
2024	9,316
2025	9,065
Thereafter	74,330
Total future lease payments	121,407
Less amount representing interest	36,497
Total obligations under operating leases	$	84,910

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4. CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

General rate case (Docket No. RP18-1126) On August 31, 2018, we filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement in our prior rate case to file a rate case no later than August 31, 2018. On September 28, 2018, the FERC issued an order accepting and suspending our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2018. On December 31, 2019, we filed a stipulation and agreement with the FERC to resolve all issues in this proceeding without the need for a hearing. On March 24, 2020, the FERC approved the settlement, which became effective on June 1, 2020. Refunds of $284.3 million were issued on July 1, 2020.

Notice of Inquiry (Docket No. PL19-4-000). On May 21, 2020, the FERC issued a “Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines” (Policy Statement) in Docket No. PL19-4-000 adopting changes to its policies concerning the calculation of a public utility return on equity (ROE). In this Policy Statement, the FERC revised its ROE policy for natural gas pipelines and oil pipelines to provide that the FERC will determine a pipeline’s ROE by averaging the results of the Discounted Cash Flow model and the Capital Asset Pricing Model, with each weighted equally. The FERC declined to adopt any additional policy changes at this time and will address all other issues concerning the determination of a pipeline’s ROE as they arise in future proceedings.

Our next general rate case must be filed no later than August 30, 2024.

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2020, we had a balance of approximately $2.4 million for the expense portion of these estimated costs, $0.7 million recorded in Accrued liabilities and $1.7 million recorded in Other Long-Term Liabilities - Other in the Consolidated Balance Sheet. At December 31, 2019, we had a balance of approximately $2.5 million for the expense portion of these estimated costs, $1.2 million recorded in Accrued liabilities and $1.3 million recorded in Other Long-Term Liabilities - Other in the Consolidated Balance Sheet.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the environmental liabilities discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Total property, plant and equipment, net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the

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regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings.

Other Matters

Various other proceedings are pending against us and are considered incidental to our operations.

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

Other Commitments

We have commitments for construction and acquisition of property, plant and equipment of approximately $14 million at December 31, 2020.

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5. DEBT AND FINANCING ARRANGEMENTS

Long-Term Debt

At December 31, 2020 and 2019, long-term debt outstanding was as follows (in thousands): 

	2020		2019
Debentures:
7.08% due 2026	$	7,500	$	7,500
7.25% due 2026	200,000		200,000
Total debentures	207,500		207,500
Notes:
7.85% due 2026	1,000,000		1,000,000
4.0% due 2028	400,000		400,000
3.25% due 2030	700,000		—
5.4% due 2041	375,000		375,000
4.45% due 2042	400,000		400,000
4.6% due 2048	600,000		600,000
3.95% due 2050	500,000		—
Total notes	3,975,000		2,775,000
Other financing obligations	1,104,143		1,115,980
Total long-term debt, including current portion	5,286,643		4,098,480
Unamortized debt issuance costs	(32,505)		(22,876)
Unamortized debt premium and discount, net	(14,358)		(10,634)
Long-term debt due within one year	(22,640)		(20,180)
Total long-term debt	$	5,217,140	$	4,044,790

Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2020, for the next five years, are as follows (in thousands): 

2021:     Other financing obligations	$	22,640
2022:     Other financing obligations	$	24,762
2023:     Other financing obligations	$	27,082
2024:     Other financing obligations	$	29,621
2025:     Other financing obligations	$	32,397

No property is pledged as collateral under any of our long-term debt issues.

Restrictive Debt Covenants

At December 31, 2020, none of our debt instruments restrict the amount of distributions to our parent, provided, however, that under the credit facility described below, we are restricted from making distributions to our parent during an event of default if we have directly incurred indebtedness under the credit facility. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels and to guarantee certain indebtedness. The indenture governing our $1 billion of 7.85 percent Senior Notes due 2026 further restricts our ability to guarantee certain indebtedness.

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Issuance and Retirement of Long-Term Debt

On May 8, 2020, we issued $700 million of 3.25 percent senior unsecured notes due 2030 and $500 million of 3.95 percent senior unsecured notes due 2050 to investors in a private debt placement. As part of the issuance, we entered into a registration rights agreement with the initial purchasers of the unsecured notes. Under the terms of the agreement, we were obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. In the fourth quarter of 2020, we filed the registration statement and completed the exchange offer.

Other Financing Obligations

During the construction of the Atlantic Sunrise and Dalton Expansion projects, we received funding from co-owners for their proportionate share of construction costs. Amounts received were recorded in Advances for construction costs and the costs associated with construction were capitalized in our Consolidated Balance Sheet. Upon placing these projects into service we began utilizing the co-owners' undivided interest in the assets, including the associated pipeline capacity, and reclassified the funding previously received from co-owners from Advances for construction costs to Long-Term Debt. The obligations, which mature in 2038 and 2052, respectively, require monthly interest and principal payments and both bear an interest rate of approximately 9 percent.

Dalton Expansion Project

During 2019, we received $0.7 million of additional funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. At December 31, 2020, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $254.4 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $2.3 million. At December 31, 2019, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $256.8 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $2.1 million.

Atlantic Sunrise Project

During 2020 and 2019, we received $8.7 million and $40.8 million, respectively, of additional funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in Atlantic Sunrise. During the fourth quarter of 2019, we also increased our financing obligation by $25 million associated with a payment received by Williams pursuant to a contract settlement with a co-owner of the Atlantic Sunrise project (See Note 9). At December 31, 2020, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $827.1 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $20.3 million. At December 31, 2019, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $839.0 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $18.1 million.

Long-Term Debt Due Within One Year

The long-term debt due within one year at December 31, 2020 and 2019 are associated with the previously described other financing obligations.

Credit Facility

In 2018, we, along with Williams and Northwest (the borrowers), the lenders named therein, and an administrative agent entered into a credit agreement (Credit Agreement) with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. We and Northwest are each subject to a $500 million borrowing sublimit. The facility made available under the Credit Agreement is initially available for five years from the Credit Agreement Effective Date (the Maturity Date). The borrowers may request an extension of the Maturity Date for an additional one-year period up to two times, to allow a Maturity Date as late as the seventh anniversary of the Credit Agreement Effective Date, subject to certain conditions. The Credit Agreement allows for same day swingline borrowings up to an aggregate amount of $200 million, subject to other utilization of aggregate commitments under the Credit Agreement. Letter of

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credit commitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Northwest, available to the borrowers. At December 31, 2020 no letters of credit have been issued and no loans to Williams were outstanding under the credit facility.

Measured as of December 31, 2020, we are in compliance with our financial covenant under the credit facility.

Various covenants may limit, among other things, a borrower's and its material subsidiaries' ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.

If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.

Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower's senior unsecured long-term debt ratings.

Williams participates in a commercial paper program and Williams management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $4.0 billion of unsecured commercial paper notes. At December 31, 2020, Williams had no outstanding commercial paper.

6. ARO TRUST

We are entitled to collect in rates the amounts necessary to fund our ARO. We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The ARO Trust carries a moderate risk portfolio. The Money Market Funds held in our ARO Trust are considered investments. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

Effective March 1, 2019, the annual ARO funding obligation based on the Docket No. RP18-1126 rate case filing was approximately $35.9 million. Pursuant to the Docket No. RP18-1126 rate case settlement, the new funding obligation (1) effective March 1, 2019 is approximately $23.8 million and (2) effective March 1, 2020 is approximately $16.0 million

Investments within the ARO Trust at fair value were as follows (in millions):

	December 31, 2020				December 31, 2019
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Money Market Funds	$	5.8	$	5.8	$	15.8	$	15.8
U.S. Equity Funds	59.9		108.0		55.3		83.3
International Equity Funds	34.2		43.7		31.8		35.4
Municipal Bond Funds	74.9		78.0		64.7		66.1
Total	$	174.8	$	235.5	$	167.6	$	200.6

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7. FAIR VALUE MEASUREMENTS

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of short-term financial assets (advances to affiliate and from affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
					(Millions)
Assets (liabilities) at December 31, 2020:
Measured on a recurring basis:
ARO Trust investments	$	235.5	$	235.5	$	235.5	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(5,239.8)		(6,949.0)		—		(6,949.0)		—
Assets (liabilities) at December 31, 2019:
Measured on a recurring basis:
ARO Trust investments	$	200.6	$	200.6	$	200.6	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(4,065.0)		(5,251.4)		—		(5,251.4)		—

Fair Value Methods

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP18-1126 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and are reported in Other Assets-Other on the accompanying Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 6 for more information regarding the ARO Trust.

Long-term debt - The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton and Atlantic Sunrise expansions, which are included within long-term debt, were determined using an income approach (See Note 5 - Debt and Financing Agreements).

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Nonrecurring fair value measurements

Approvals required for the Northeast Supply Enhancement project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now require impairment. As of December 31, 2020, the estimated fair value of the materials within the capitalized project costs were determined to be $41.5 million and considered other internal uses and salvage values for the Property, plant, and equipment, net, a Level 3 measurement. The remaining capitalized costs were determined to have no fair value. As a result we recognized an impairment charge of $170.1 million during the fourth quarter of 2020.

8. BENEFIT PLANS

Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below.

Pension and Other Postretirement Benefit Plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams were $9.1 million, $9.6 million and $12.8 million for 2020, 2019, and 2018, respectively. Included in our pension costs are settlement charges of $3.7 million and $2.7 million for 2020 and 2018, respectively.

Williams makes annual cash contributions to the pension plans, based on annual actuarial estimates, which Transco recovers through rates that are set through periodic general rate filings. Effective with the Docket No. RP18-1126 rate case settlement, any amounts of annual contributions that fall below a threshold are recorded as adjustments to income and refunded through future rate adjustments. The amounts of deferred pension collections recorded as regulatory liabilities at December 31, 2020 and 2019 were $38.9 million and $43.3 million, respectively. Effective with the Docket No. RP18-1126 rate case settlement, the pension regulatory liability as of March 1, 2019 is being amortized over a five year period.

Williams provides subsidized retiree health care and life insurance benefits to certain eligible participants. Generally, participants that were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries, are eligible for subsidized retiree health care benefits. We recognized other postretirement benefit income of $4.5 million, $4.1 million and $5.9 million for 2020, 2019, and 2018, respectively.

We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to expense and collected or refunded through future rate adjustments. The amount of other postretirement benefits costs deferred as regulatory liabilities at December 31, 2020 and 2019 are $60.9 million and $68.0 million, respectively. Effective with the Docket No. RP18-1126 rate case settlement, the other postretirement benefits regulatory liability as of March 1, 2019 is being amortized over a period of approximately five years.

Defined Contribution Plan

Williams maintains a defined contribution plan for substantially all of its employees. Williams charged us compensation expense of $9.5 million, $7.9 million, and $7.9 million in 2020, 2019, and 2018, respectively, for Williams’ company contributions to this plan.

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Employee Stock-Based Compensation Plan Information

The Williams Companies, Inc. 2007 Incentive Plan, as subsequently amended and restated, (Plan) provides for Williams’ common stock-based awards to both employees and non-management directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.

Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. We are also billed for our proportionate share of Williams’ and other affiliates’ stock-based compensation expense through various allocation processes.

Total stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 was $4.0 million, $5.9 million, and $6.3 million, respectively, excluding amounts allocated from WPZ and Williams.

9. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Major Customers

Operating revenues received from three of our major customers in 2020, 2019 and 2018 are as follows (in millions): 

	2020		2019		2018
Dominion Energy, Inc.	$	248.5	$	250.7	$	113.5
Duke Energy Corporation	232.8		222.5		194.5
The Southern Company, Inc.	216.4		216.1		166.2

Affiliates

We are a participant in Williams' cash management program, and we make advances to and receive advances from Williams. At December 31, 2020, our advances to Williams totaled approximately $642.7 million. These advances are represented by demand notes and are classified as Receivables - Advances to affiliate in the accompanying Consolidated Balance Sheet. At December 31, 2019, our advances from Williams totaled approximately $252.5 million. These advances are represented by demand notes and are classified as Payables - Advances from affiliate in the accompanying Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest expense and income are recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on Williams' excess cash at the end of each month. At December 31, 2020, the interest rate was 0.01 percent.

Included in Operating Revenues in the accompanying Consolidated Statement of Comprehensive Income for 2020, 2019 and 2018 are revenues received from affiliates of $11.4 million, $10.5 million, and $10.1 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Consolidated Statement of Comprehensive Income for 2020, 2019 and 2018 is purchased gas cost from affiliates of $5.6 million, $4.0 million, and $5.4 million, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to

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us of our costs of doing business incurred by Williams. We were billed $352.1 million, $412.4 million, and $395.3 million during 2020, 2019 and 2018, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Consolidated Statement of Comprehensive Income. Included in the amounts billed to us for 2019 are costs for severance and other related costs associated with a reduction in workforce of $28.8 million.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $5.1 million, $4.4 million, and $4.7 million in 2020, 2019 and 2018, respectively.

We made equity distributions to our parent of $1,020 million, $824 million and $490 million during 2020, 2019 and 2018, respectively.

During 2020 and 2018, our parent made contributions totaling $115 million and $340 million, respectively, to us. During February 2021, our parent made an additional $60 million contribution to us.

During 2019, we recognized a non-cash distribution of $25 million to our parent related to a settlement agreement between Williams and a co-owner in our Atlantic Sunrise project. Although the agreement was between Williams and a third party, since the agreement was in part related to our Atlantic Sunrise project, the settlement amount was added to our Atlantic Sunrise project financing obligation. (See Note 5)

Effective December 31, 2019, we made a $36.6 million non-cash distribution to our parent of our interests in our wholly-owned subsidiaries, Cardinal Operating Company, LLC, Pine Needle Operating Company, LLC, TransCarolina LNG Company, LLC, and TransCardinal Company, LLC.

10. ASSET RETIREMENT OBLIGATIONS

These accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

During 2020 and 2019, our overall asset retirement obligation changed as follows (in thousands): 

	2020		2019
Beginning balance	$	459,209	$	394,323
Accretion	23,142		21,806
New obligations	1,154		103
Changes in estimates of existing obligations (1)	(21,889)		49,070
Property dispositions/obligations settled	(11,115)		(6,093)
Ending balance	$	450,501	$	459,209

(1)    Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rate, current estimates for removal costs, discount rates, and the estimated remaining life of assets. The decrease in 2020 is primarily due to a decrease in the inflation rate. The increase in 2019 is primarily due to an increase in the inflation rate and a decrease in the discount rate.

We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding our ARO (See Note 6).

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11. REGULATORY ASSETS AND LIABILITIES

The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2020 and December 31, 2019 are as follows (in millions):

Regulatory Assets	2020		2019
Grossed-up deferred taxes on equity funds used during construction	$	36.1	$	37.5
Asset retirement obligations	139.5		147.6
Asset retirement costs - Eminence	36.6		42.2
Deferred cash out	70.0		64.4
Fuel cost	34.1		40.2
Electric power cost	7.8		8.4
Slug catcher	6.4		6.6
Other	14.2		13.5
Total Regulatory Assets	$	344.7	$	360.4

Regulatory Liabilities	2020		2019
Negative salvage	$	504.5	$	482.6
Deferred taxes - liability	392.8		423.5
Sentinel meter station depreciation	6.8		6.6
Postretirement benefits other than pension	60.9		68.0
Pension	38.9		43.3
Other	—		0.3
Total Regulatory Liabilities	$	1,003.9	$	1,024.3

The significant regulatory assets and liabilities include:

Grossed-up deferred taxes on equity funds used during construction: Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

Asset retirement obligations: Regulatory asset balance established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates (See Note 10).

Asset retirement costs - Eminence: Regulatory asset balance associated with the Eminence Storage Field retirement costs. The regulatory asset is being recovered through our rates and is being amortized to expense consistent with the amounts collected in rates.

Deferred cash out: This amount represents the deferral of gains or losses on the purchases and sales of gas imbalances with shippers. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual cash out filing periods.

Fuel cost: This amount represents the difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual fuel tracker filing periods.

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Electric power cost: This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods.

Slug catcher: This amount represents certain costs associated with the replacement of a component of a slug catcher which was included in the Docket No. RP18-1126 rate case settlement. A regulatory asset has been established to recognize the recovery of Transco’s investment in the slug catcher as it is collected through Transco’s depreciation rates and is being amortized at the onshore transmission plant depreciation rate.

Negative salvage: Our rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the cumulative residual amount of recoveries through rates, net of expenditures associated with these retirement costs.

Deferred taxes - liability: Regulatory liability balance was established as a result of a decrease to rate base deferred taxes due to a decrease to the effective federal income tax rate. The timing of the refund of the regulatory liability to rate payers is stated in the Docket No. RP18-1126 rate case settlement.

Sentinel meter station depreciation: This amount reflects the incremental depreciation being recorded related to the meter station modifications made for three of the Sentinel shippers. These modifications will be recovered through a surcharge over a defined period of time as stated in the Sentinel FERC order. The incremental depreciation represents the difference between the FERC granted depreciation rate for such facilities in the last rate case as compared to the depreciation rates in the Sentinel order which are based on the contractual terms in the surcharge agreements. The incremental depreciation will be recorded through the end of the contractual term and then will be amortized.

Postretirement benefits other than pension: We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and the amounts recovered in rates are recorded as regulatory assets or liabilities to be collected or refunded through future rate adjustments. These amounts are not included in the rate base. Effective with the Docket No. RP18-1126 rate case settlement, the other postretirement benefits regulatory liability balance as of March 1, 2019, is currently being amortized. (See Note 8).

Pension: We recover the actuarially determined pension cash contributions through rates that are set through periodic general rate filings. Effective with the Docket No. RP18-1126 rate case settlement, any amounts of annual contributions that fall below the threshold are recorded as adjustments to income and refunded through future rate adjustments. Effective with the Docket No. RP18-1126 rate case settlement, the pension regulatory liability balance as of March 1, 2019, is currently being amortized. (See Note 8).

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Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Our management, including our Senior Vice President and our Vice President and Chief Accounting Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a—15(e) and 15d—15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Chief Accounting Officer. Based upon that evaluation, our Senior Vice President and our Vice President and Chief Accounting Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes during the fourth quarter of 2020 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a – 15(f) and 15d – 15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to our management regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

57

Under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Chief Accounting Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2020, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we concluded that, as of December 31, 2020, our internal control over financial reporting was effective.

This annual report does not include a report of the company’s registered public accounting firm regarding internal control over financial reporting. A report by the company’s registered public accounting firm is not required pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

Item 9B. Other information

None.

PART III

Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, the information required by Items 10, 11, 12, and 13, is omitted.

Item 14. Principal Accounting Fees and Services

Fees for professional services provided by our independent registered public accounting firm in each of the last two fiscal years in each of the following categories are (in millions):

	2020		2019
Audit fees	$	1.4	$	1.4
Audit-related fees	—		—
Tax fees	—		—
All other fees	—		—
Total fees	$	1.4	$	1.4

Fees for audit services include fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, the reviews for other SEC and FERC filings, and accounting consultation.

As a wholly owned subsidiary of Williams, we do not have a separate audit committee.  The Williams Audit Committee is responsible for the appointment, compensation, retention, and oversight of Ernst & Young LLP (“EY”) as such appointment relates to us and Williams’ other affiliates. The Williams Audit Committee is responsible for overseeing the determination of fees associated with EY’s audit of our financial statements. The Williams Audit Committee has established a policy regarding pre-approval of all audit and non-audit services provided by EY to Williams and its affiliates. On an ongoing basis, management presents specific projects and categories of service, including projects and categories of service relating to us, to the Williams Audit Committee to request advance approval. The Williams Audit Committee reviews those requests and advises management if the Williams Audit Committee approves the engagement of EY. On a periodic basis, management reports to the Williams Audit Committee regarding the actual spending for such projects and services compared to the approved amounts. The Williams Audit Committee may also delegate the authority to pre-approve audit and permitted non-audit services, excluding services related to internal control over financial reporting, to a subcommittee of one or more committee members, provided that any such pre-approvals are reported on at a subsequent Williams Audit Committee meeting.

58

PART IV

Item 15. Exhibits and Financial Statement Schedules

	Page Reference to 2020 10-K
A. 1 and 2. Transcontinental Gas Pipe Line Company, LLC financials
Index
Covered by Report of Independent Registered Public Accounting Firm:
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018	31
Consolidated Balance Sheet as of December 31, 2020 and 2019	32
Consolidated Statement of Member’s Equity for the Years Ended December 31, 2020, 2019 and 2018	34
Consolidated Statement of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018	35
Notes to Consolidated Financial Statements	37
The following schedules are omitted because of the absence of the conditions under which they are required: I, II, III, IV, and V.

59

3. Exhibits:

Exhibit Number	Description
2	Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
3.1	Certificate of Formation executed as of December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
3.2	Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our quarterly report on Form 10-Q (File No. 001-07584) and incorporated herein by reference).
4.1	Senior Indenture dated July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to our registration statement Form S-3 (File No. 333-02155) and incorporated herein by reference).
4.2	Indenture, dated as of August 12, 2011 between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on August 12, 2011 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.3	Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on July 16, 2012 as Exhibit 4.1 to our current report Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.4	Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.5	Indenture, dated as of March 15, 2018, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 15, 2018 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.6	Indenture, dated as of May 8, 2020, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 8, 2020 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
10.1	Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transcontinental Gas Pipe Line Company, LLC (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s, Form 8-K (File No. 001-32599) and incorporated herein by reference).
10.2	Assignment Agreement dated February 13, 2013 by and between Transco Pipeline Services LLC and Williams WPC-I, LLC, effective January 1, 2013 (filed on February 27, 2013 as Exhibit 10.2 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
10.3	Credit Agreement dated as of July 13, 2018, between The Williams Companies, Inc., Northwest Pipeline LLC, and Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on July 17, 2018 as Exhibit 10.1 to The Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
23.1*	Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm of Transcontinental Gas Pipe Line Company, LLC.
31.1*	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32 **	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

60

101.INS*	XBRL Instance Document. The instance document dos not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH*	XBRL Taxonomy Extension Schema.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase.
104*	Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101).

*     Filed herewith.
**    Furnished herewith.

Item 16. Form 10-K Summary

Not applicable.

61

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC (Registrant)
By:	/s/ Billeigh W. Mark
	Billeigh W. Mark
	Controller

Date: February 24, 2021

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature	Title
/s/ Scott A. Hallam	Management Committee Member and Senior Vice President (Principal Executive Officer)
Scott A. Hallam
/s/ John D. Porter	Vice President and Chief Accounting Officer (Principal Financial Officer)
John D. Porter
/s/ Billeigh W. Mark	Controller (Principal Accounting Officer)
Billeigh W. Mark

Date: February 24, 2021

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statement (Form S-4 No. 333-249803) of Transcontinental Gas Pipe Line Company, LLC and in the related Prospectus of our report dated February 24, 2021, with respect to the consolidated financial statements of Transcontinental Gas Pipe Line Company, LLC included in this Annual Report (Form 10-K) for the year ended December 31, 2020.

/s/ Ernst & Young LLP

Houston, Texas

February 24, 2021

EX-31.1

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Scott A. Hallam, certify that:

1.I have reviewed this annual report on Form 10-K of Transcontinental Gas Pipe Line Company, LLC;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 24, 2021

By:	/s/ Scott A. Hallam
	Scott A. Hallam
	Senior Vice President
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

SECTION 302 CERTIFICATION

I, John D. Porter, certify that:

1.I have reviewed this annual report on Form 10-K of Transcontinental Gas Pipe Line Company, LLC;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 24, 2021

By:	/s/ John D. Porter
	John D. Porter
	Vice President and Chief Accounting Officer
	(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Transcontinental Gas Pipe Line Company, LLC (the “Company”) on Form 10-K for the period ending December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Scott A. Hallam

Scott A. Hallam

Senior Vice President

February 24, 2021

/s/ John D. Porter

John D. Porter

Vice President and Chief Accounting Officer

February 24, 2021

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.

XML

Document and Entity Information Document - shares	12 Months Ended
	Dec. 31, 2020	Feb. 24, 2021
Document and Entity Information [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Entity File Number	1-7584
Entity Registrant Name	TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	74-1079400
Entity Address, Address Line One	2800 Post Oak Boulevard
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056
City Area Code	713
Local Phone Number	215-2000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Central Index Key	0000099250
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		0

XML

Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Revenues:
Natural gas sales	$ 80,351	$ 105,884	$ 127,821
Natural gas transportation	2,241,760	2,188,058	1,784,794
Natural gas storage	161,956	147,687	136,666
Other	20,246	11,113	10,600
Total operating revenues	2,504,313	2,452,742	2,059,881
Operating Costs and Expenses:
Cost of natural gas sales	80,351	105,884	127,821
Cost of natural gas transportation	53,654	50,273	38,749
Operation and maintenance	323,093	382,513	399,293
Administrative and general	184,768	217,000	189,588
Depreciation and amortization	463,757	433,480	366,566
Taxes — other than income taxes	83,687	76,632	67,537
Impairment of assets	170,128	0	0
Regulatory credit resulting from tax rate changes	(30,752)	(24,202)	(20,867)
Other expense, net	5,461	6,195	64,918
Total operating costs and expenses	1,334,147	1,247,775	1,233,605
Operating Income	1,170,166	1,204,967	826,276
Other (Income) and Other Expenses:
Interest expense - affiliate	892	2,319	60
- other	311,451	283,990	218,126
Interest income - affiliate	(132)	(89)	(7,606)
- other	(4,265)	(4,349)	(3,448)
Allowance for equity and borrowed funds used during construction (AFUDC)	(22,648)	(39,289)	(116,347)
Equity in earnings of unconsolidated affiliates	0	(3,216)	(1,068)
Miscellaneous other (income) expenses, net	4,832	2,305	(4,520)
Total other (income) and other expenses	290,130	241,671	85,197
Net Income	880,036	963,296	741,079
Other comprehensive income:
Equity interest in unrealized gain on interest rate hedges (includes $(162) and $(143) for the years ended December 31, 2019 and 2018, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges)	0	(641)	197
Comprehensive Income	$ 880,036	$ 962,655	$ 741,276

XML

Consolidated Statement of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Statement [Abstract]
Accumulated other comprehensive income reclassification for realized losses (gains) on interest rate hedges	$ (162)	$ (143)

XML

Consolidated Balance Sheet - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current Assets:
Cash	$ 0	$ 0
Receivables:
Trade	223,864	242,416
Affiliates	1,011	669
Advances to affiliate	642,734	0
Other	14,660	10,850
Transportation and exchange gas receivables	4,627	6,360
Inventories:
Gas in storage, at original cost	926	857
Gas available for customer nomination, at average cost	7,909	20,653
Materials and supplies, at average cost	47,462	43,482
Regulatory assets	62,861	69,440
Other	13,847	11,240
Total current assets	1,019,901	405,967
Property, Plant and Equipment:
Natural gas transmission plant	17,123,779	16,764,904
Less-Accumulated depreciation and amortization	4,802,256	4,438,077
Total property, plant and equipment, net	12,321,523	12,326,827
Other Assets:
Regulatory assets	281,870	290,923
Right-of-use assets	78,899	84,979
Other	252,051	210,017
Total other assets	612,820	585,919
Total assets	13,954,244	13,318,713
Payables:
Trade	109,636	155,676
Affiliates	32,676	47,740
Advances from affiliate	0	252,549
Cash overdrafts	18,813	28,292
Transportation and exchange gas payables	1,905	3,961
Reserve for rate refunds	0	188,842
Accrued liabilities:
Property and other taxes	20,177	19,034
Interest	75,806	70,572
Regulatory liabilities	57,086	57,359
Customer deposits	24,686	30,551
Customer advances	27,082	27,207
Asset retirement obligations	52,764	32,704
Other	41,864	19,060
Long-term debt due within one year	22,640	20,180
Total current liabilities	485,135	953,727
Long-Term Debt	5,217,140	4,044,790
Other Long-Term Liabilities:
Asset retirement obligations	397,737	426,505
Regulatory liabilities	946,774	966,961
Advances for construction costs	38,585	16,533
Deferred revenue	205,030	215,598
Lease liability	78,688	84,528
Other	4,336	4,288
Total other long-term liabilities	1,671,150	1,714,413
Contingent Liabilities and Commitments (Note 4)
Member's Equity:
Member's capital	4,543,499	4,428,499
Retained earnings	2,037,320	2,177,284
Total member's equity	6,580,819	6,605,783
Total liabilities and member's equity	$ 13,954,244	$ 13,318,713

XML

Consolidated Statement of Member's Equity Consolidated Statement of Member's Equity - USD ($) $ in Thousands	Total	Member's Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period at Dec. 31, 2017		$ 4,088,499	$ 1,848,488	$ 337
Cash contributions from parent	$ 340,000	340,000
Net income	741,079		741,079
Cash distributions to parent	(490,000)		(490,000)
Non-cash distribution to parent			0
Non-cash distribution of investments in subsidiaries			0	0
Equity interest in unrealized gain (loss) on interest rate hedge	197			197
Balance at end of period at Dec. 31, 2018	6,528,600	4,428,499	2,099,567	534
Cash contributions from parent	0	0
Net income	963,296		963,296
Cash distributions to parent	(824,000)		(824,000)
Non-cash distribution to parent			(25,000)
Non-cash distribution of investments in subsidiaries			(36,579)	(107)
Equity interest in unrealized gain (loss) on interest rate hedge	(641)			(641)
Balance at end of period at Dec. 31, 2019	6,605,783	4,428,499	2,177,284	0
Cash contributions from parent	115,000	115,000
Net income	880,036		880,036
Cash distributions to parent	(1,020,000)		(1,020,000)
Non-cash distribution to parent			0
Non-cash distribution of investments in subsidiaries			0	0
Equity interest in unrealized gain (loss) on interest rate hedge	0			0
Balance at end of period at Dec. 31, 2020	$ 6,580,819	$ 4,543,499	$ 2,037,320	$ 0

XML

Statement of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income	$ 880,036	$ 963,296	$ 741,079
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	463,757	433,480	366,566
Impairment of assets	170,128	0	0
Allowance for equity funds used during construction (equity AFUDC)	(14,889)	(28,785)	(87,111)
Regulatory credit resulting from tax rate changes	(30,752)	(24,202)	(20,867)
Equity in earnings of unconsolidated affiliates	0	(3,216)	(1,068)
Distributions from unconsolidated affiliates	0	4,908	3,250
Changes in operating assets and liabilities:
Receivables - affiliates	(342)	582	91
Receivables - trade and other	14,742	(52,307)	(30,776)
Transportation and exchange gas receivable	1,733	(1,845)	(1,310)
Regulatory assets - current	6,579	26,330	1,379
Regulatory assets - non-current	11,361	3,622	(8,605)
Inventories	8,695	(1,787)	(23,178)
Payables - affiliates	(15,064)	(2,981)	7,307
Payables - trade	(915)	(18,842)	(35,869)
Accrued liabilities	22,881	(1,723)	40,993
Asset retirement obligations	12,027	15,713	24,659
Reserve for rate refunds	(188,842)	188,842	0
Deferred Revenue	(10,568)	(10,566)	(10,565)
Other, net	(36,990)	(36,365)	10,317
Net cash provided by operating activities	1,293,577	1,454,154	976,292
Cash flows from financing activities:
Proceeds from long-term debt	1,195,629	0	993,440
Proceeds from other financing obligations	8,725	41,513	50,269
Retirement of long-term debt	0	0	(250,000)
Payments on other financing obligations	(20,366)	(17,436)	(3,705)
Payments of debt issuance costs	(11,441)	0	(10,148)
Cash distributions to parent	(1,020,000)	(824,000)	(490,000)
Cash contributions from parent	115,000	0	340,000
Advances from affiliate, net	(252,549)	252,549	0
Net cash provided by (used in) financing activities	14,998	(547,374)	629,856
Cash flows from investing activities:
Capital expenditures	(649,459)	(901,374)	(2,326,672)
Contributions and advances for construction costs	35,284	47,034	408,912
Disposal of property, plant and equipment, net	(43,900)	(45,720)	(26,469)
Advances to affiliate, net	(642,734)	33,034	362,213
Contributions to unconsolidated affiliates	0	12,250	0
Purchase of ARO Trust investments	(53,357)	(72,946)	(51,793)
Proceeds from sale of ARO Trust investments	45,591	45,479	27,661
Other, net	0	37	0
Net cash used in investing activities	(1,308,575)	(906,780)	(1,606,148)
Increase (decrease) in cash	0	0	0
Cash at beginning of period	0	0	0
Cash at end of period	0	0	0
Increase to property, plant and equipment, exclusive of equity AFUDC	(582,896)	(854,761)	(2,085,888)
Changes in related accounts payable and accrued liabilities	(66,563)	(46,613)	(240,784)
Capital expenditures	(649,459)	(901,374)	(2,326,672)
Supplemental Cash Flow Elements [Abstract]
Interest (exclusive of amount capitalized)	299,470	268,559	168,418
Income taxes	$ 352	$ 76	$ 632

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Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and, unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.”

Transco was indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which was consolidated by The Williams Companies, Inc. (Williams). On August 10, 2018, Williams completed a merger with WPZ, pursuant to which Williams acquired all of the publicly held outstanding common units of WPZ in exchange for shares of Williams' common stock (WPZ Merger). Williams continued as the surviving entity. Transco is now indirectly owned by Williams.

Transco is a single member limited liability company, and as such, single member losses are limited to the amount of its investment.

Nature of Operations

We are an interstate natural gas transmission company that owns and operates a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania.

Regulatory Accounting

We are regulated by the Federal Energy Regulatory Commission (FERC). Accounting Standards Codification (ASC) Regulated Operations, (Topic 980), provides that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management's expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. We record certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations (ARO), and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements.

Basis of Presentation

Williams’ acquisition of us in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At

December 31, 2020, the remaining property, plant and equipment allocation was approximately $0.5 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.

Principles of Consolidation

The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments prior to December 31, 2019 (See Note 9) consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $4.9 million and $3.2 million in 2019 and 2018, respectively. We made a $12.3 million contribution to Pine Needle in the second quarter of 2019.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; and 6) asset retirement obligations.

Revenue Recognition

Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators.

Service revenue contracts from our gas pipeline business contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our natural gas sales contracts have a single performance obligation with revenue recognized at a point in time when the natural gas has been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset.

Operating Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual

commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following:

•Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

•Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Natural Gas Sales

In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).

Contract Liabilities

Our contract liabilities consist of advance payments from customers, which include prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods, and are classified as current or non-current according to when such amounts are expected to be recognized. Current and non-current contract liabilities are included within Accrued Liabilities and Other Long-Term Liabilities - Deferred revenue, respectively, in our Consolidated Balance Sheet.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component.

Leases

We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions. We recognize a

lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. As an accounting policy, we have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.

We used judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2020, 2019 and 2018 are as follows:

Category of Property	2020-2019 (1)	2018
Gathering facilities	0% - 1.00%	1.35% - 2.50%
Storage facilities	1.86% -  2.05%	2.10% -  2.25%
Onshore transmission facilities	2.50%  -  7.13%	2.61%  -  5.00%
Offshore transmission facilities	1.25%  -  1.25%	1.20%  -  1.20%

(1)     Changes in depreciation rates in 2019 were due to placing into effect the rates in Docket No. RP18-1126

on March 1, 2019.

We record a liability and increase the basis in the underlying asset for the present value of each expected future Asset Retirement Obligations (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates.

Impairment of Long-lived Assets

We evaluate our long-lived assets, including capitalized project development costs, for impairment when events or changes in circumstances indicate, in our management's judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred, we compare our management's estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

Judgments and assumptions are inherent in our estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize.

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $7.7 million, $10.5 million, and $29.2 million, for 2020, 2019 and 2018, respectively. The allowance for equity funds was $14.9 million, $28.8 million, and $87.1 million, for 2020, 2019 and 2018, respectively.

Income Taxes

We are a natural gas company organized as a pass-through entity and our taxable income or loss is consolidated on the federal income tax return of our parent, Williams. We generally are treated as a pass-through entity for state and local income tax purposes, and those taxes are generally borne on a consolidated basis by Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We estimate the reserves, considering current expected credit losses (as discussed below in Accounting Standards Issued and Adopted). We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables.

Gas Imbalances

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2020 and 2019. We utilize the average cost method of accounting for gas imbalances.

Deferred Cash Out

Most transportation imbalances are settled in cash on a monthly basis (cash-out). In accordance with our tariff, revenues received from the cash-out of transportation imbalances in excess of costs incurred are deferred and offset by the deferral of costs incurred in excess of revenues received. At the end of each annual August through July reporting period, if the cumulative revenues received exceed the costs incurred, the over recovered amounts are refunded. If the cumulative revenues received are less than the costs incurred, the net under recovered amounts are carried forward and offset against any future net over recoveries that may occur in a subsequent annual reporting period.

Gas Inventory

We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2020 and 2019, Gas in Storage, at LIFO, was zero. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.

Materials and Supplies Inventory

All inventories are stated at average cost. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2020 and 2019.

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Pension and Other Postretirement Benefits

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 8.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost.

Cash Flows from Operating Activities and Cash Equivalents

We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.

Accounting Standards Issued and Adopted

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changed the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We adopted ASU 2016-13 effective January 1, 2020, which primarily applied to our short-term trade receivables. There was no cumulative effect adjustment to retained earnings upon adoption.

The majority of our trade receivable balances are due within 30 days. We monitor the credit quality of our counterparties through review of collection trends, credit ratings, and other analysis, such as bankruptcy monitoring. Financial assets are evaluated as one pool. Changes in counterparty risk factors could lead to reassessment of the composition of our financial assets as one pool. We calculate our allowance for credit losses incorporating an aging method. In estimating our expected credit losses, we utilized historical loss rates over many years. Our expected credit loss estimate considered both internal and external forward-looking commodity price expectations, as well as counterparty credit ratings, and factors impacting their near-term liquidity.

Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. We do not have a material amount of significantly aged receivables at December 31, 2020.

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Revenue Recognition (Notes)

12 Months Ended

Dec. 31, 2020

Revenue Recognition [Abstract]

Revenue from Contract with Customer [Text Block]

2. REVENUE RECOGNITION

Revenue by Category

Our revenue disaggregation by major service line includes Natural gas sales, Natural gas transportation, Natural gas storage, and Other, which are separately presented on the Condensed Consolidated Statement of Comprehensive Income.

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	December 31, 2020		December 31, 2019
	(Thousands)
Balance at beginning of period	$	226,164	$	236,730
Recognized in revenue	(10,568)		(10,566)
Balance at end of period	$	215,596	$	226,164

Remaining Performance Obligations

Our remaining performance obligations primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs, net of estimated reserve for refund, for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. This table excludes the variable consideration component for commodity charges. Certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligation as of December 31, 2020, do not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.

The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2020.

	Contract Liabilities		Remaining Performance Obligations
	(Thousands)
2021	$	10,566	$	2,349,047
2022	10,566		2,196,621
2023	10,566		2,040,685
2024	10,568		1,487,964
2025	10,566		1,453,924
Thereafter	162,764		12,231,530
Total	$	215,596	$	21,759,771

Accounts Receivable Receivables from contracts with customers are included within Receivables - Trade and Receivables - Affiliates and receivables that are not related to contracts with customers are included within the balance of Receivables - Advances to affiliate and Receivables - Other in our Consolidated Balance Sheet.

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Leases (Notes)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Lessee, Operating Leases [Text Block]

LEASES

We are a lessee through non-cancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions.

	Twelve Months Ended   December 31,
	2020			2019
	(Thousands)
Lease Cost:
Operating lease cost	$	9,691		$	10,276
Variable lease cost	3,135			6,867
Total lease cost	$	12,826		$	17,143
Cash paid for amounts included in the measurement of operating lease liabilities	$	3,690		$	9,986
	December 31,
	2020			2019
	(Thousands)
Other Information:
Right-of-use assets	$	78,899		$	84,979
Operating lease liabilities:
Current (included in Accrued liabilities - Other in our Consolidated Balance Sheet)	$	6,222		$	811
Lease liability	$	78,688		$	84,528
Weighted-average remaining lease term - operating leases (years)	15			15
Weighted-average discount rate - operating leases	4.66		%	4.65		%

Prior to adopting ASU 2016-02, total rent expense was $10.8 million in 2018 and primarily included in Operation and maintenance and Administrative and general expenses in the Consolidated Statement of Comprehensive Income.

As of December 31, 2020, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:

	(Thousands)
2021	$	9,471
2022	9,611
2023	9,614
2024	9,316
2025	9,065
Thereafter	74,330
Total future lease payments	121,407
Less amount representing interest	36,497
Total obligations under operating leases	$	84,910

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Contingent Liabilities and Commitments (Notes)

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities and Commitments

CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

General rate case (Docket No. RP18-1126) On August 31, 2018, we filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement in our prior rate case to file a rate case no later than August 31, 2018. On September 28, 2018, the FERC issued an order accepting and suspending our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2018. On December 31, 2019, we filed a stipulation and agreement with the FERC to resolve all issues in this proceeding without the need for a hearing. On March 24, 2020, the FERC approved the settlement, which became effective on June 1, 2020. Refunds of $284.3 million were issued on July 1, 2020.

Notice of Inquiry (Docket No. PL19-4-000). On May 21, 2020, the FERC issued a “Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines” (Policy Statement) in Docket No. PL19-4-000 adopting changes to its policies concerning the calculation of a public utility return on equity (ROE). In this Policy Statement, the FERC revised its ROE policy for natural gas pipelines and oil pipelines to provide that the FERC will determine a pipeline’s ROE by averaging the results of the Discounted Cash Flow model and the Capital Asset Pricing Model, with each weighted equally. The FERC declined to adopt any additional policy changes at this time and will address all other issues concerning the determination of a pipeline’s ROE as they arise in future proceedings.

Our next general rate case must be filed no later than August 30, 2024.

Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2020, we had a balance of approximately $2.4 million for the expense portion of these estimated costs, $0.7 million recorded in Accrued liabilities and $1.7 million recorded in Other Long-Term Liabilities - Other in the Consolidated Balance Sheet. At December 31, 2019, we had a balance of approximately $2.5 million for the expense portion of these estimated costs, $1.2 million recorded in Accrued liabilities and $1.3 million recorded in Other Long-Term Liabilities - Other in the Consolidated Balance Sheet.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the environmental liabilities discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Total property, plant and equipment, net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the

regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings.

Other Matters

Various other proceedings are pending against us and are considered incidental to our operations.

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

Other Commitments

We have commitments for construction and acquisition of property, plant and equipment of approximately $14 million at December 31, 2020.

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Debt and Financing Arrangements (Notes)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt, Financing Arrangements and Leases

DEBT AND FINANCING ARRANGEMENTS

Long-Term Debt

At December 31, 2020 and 2019, long-term debt outstanding was as follows (in thousands): 

	2020		2019
Debentures:
7.08% due 2026	$	7,500	$	7,500
7.25% due 2026	200,000		200,000
Total debentures	207,500		207,500
Notes:
7.85% due 2026	1,000,000		1,000,000
4.0% due 2028	400,000		400,000
3.25% due 2030	700,000		—
5.4% due 2041	375,000		375,000
4.45% due 2042	400,000		400,000
4.6% due 2048	600,000		600,000
3.95% due 2050	500,000		—
Total notes	3,975,000		2,775,000
Other financing obligations	1,104,143		1,115,980
Total long-term debt, including current portion	5,286,643		4,098,480
Unamortized debt issuance costs	(32,505)		(22,876)
Unamortized debt premium and discount, net	(14,358)		(10,634)
Long-term debt due within one year	(22,640)		(20,180)
Total long-term debt	$	5,217,140	$	4,044,790

Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2020, for the next five years, are as follows (in thousands): 

2021:     Other financing obligations	$	22,640
2022:     Other financing obligations	$	24,762
2023:     Other financing obligations	$	27,082
2024:     Other financing obligations	$	29,621
2025:     Other financing obligations	$	32,397

No property is pledged as collateral under any of our long-term debt issues.

Restrictive Debt Covenants

At December 31, 2020, none of our debt instruments restrict the amount of distributions to our parent, provided, however, that under the credit facility described below, we are restricted from making distributions to our parent during an event of default if we have directly incurred indebtedness under the credit facility. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels and to guarantee certain indebtedness. The indenture governing our $1 billion of 7.85 percent Senior Notes due 2026 further restricts our ability to guarantee certain indebtedness.

Issuance and Retirement of Long-Term Debt

On May 8, 2020, we issued $700 million of 3.25 percent senior unsecured notes due 2030 and $500 million of 3.95 percent senior unsecured notes due 2050 to investors in a private debt placement. As part of the issuance, we entered into a registration rights agreement with the initial purchasers of the unsecured notes. Under the terms of the agreement, we were obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. In the fourth quarter of 2020, we filed the registration statement and completed the exchange offer.

Other Financing Obligations

During the construction of the Atlantic Sunrise and Dalton Expansion projects, we received funding from co-owners for their proportionate share of construction costs. Amounts received were recorded in Advances for construction costs and the costs associated with construction were capitalized in our Consolidated Balance Sheet. Upon placing these projects into service we began utilizing the co-owners' undivided interest in the assets, including the associated pipeline capacity, and reclassified the funding previously received from co-owners from Advances for construction costs to Long-Term Debt. The obligations, which mature in 2038 and 2052, respectively, require monthly interest and principal payments and both bear an interest rate of approximately 9 percent.

Dalton Expansion Project

During 2019, we received $0.7 million of additional funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. At December 31, 2020, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $254.4 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $2.3 million. At December 31, 2019, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $256.8 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $2.1 million.

Atlantic Sunrise Project

During 2020 and 2019, we received $8.7 million and $40.8 million, respectively, of additional funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in Atlantic Sunrise. During the fourth quarter of 2019, we also increased our financing obligation by $25 million associated with a payment received by Williams pursuant to a contract settlement with a co-owner of the Atlantic Sunrise project (See Note 9). At December 31, 2020, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $827.1 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $20.3 million. At December 31, 2019, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $839.0 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $18.1 million.

Long-Term Debt Due Within One Year

The long-term debt due within one year at December 31, 2020 and 2019 are associated with the previously described other financing obligations.

Credit Facility

In 2018, we, along with Williams and Northwest (the borrowers), the lenders named therein, and an administrative agent entered into a credit agreement (Credit Agreement) with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. We and Northwest are each subject to a $500 million borrowing sublimit. The facility made available under the Credit Agreement is initially available for five years from the Credit Agreement Effective Date (the Maturity Date). The borrowers may request an extension of the Maturity Date for an additional one-year period up to two times, to allow a Maturity Date as late as the seventh anniversary of the Credit Agreement Effective Date, subject to certain conditions. The Credit Agreement allows for same day swingline borrowings up to an aggregate amount of $200 million, subject to other utilization of aggregate commitments under the Credit Agreement. Letter of

credit commitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Northwest, available to the borrowers. At December 31, 2020 no letters of credit have been issued and no loans to Williams were outstanding under the credit facility.

Measured as of December 31, 2020, we are in compliance with our financial covenant under the credit facility.

Various covenants may limit, among other things, a borrower's and its material subsidiaries' ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.

If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.

Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower's senior unsecured long-term debt ratings.

Williams participates in a commercial paper program and Williams management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $4.0 billion of unsecured commercial paper notes. At December 31, 2020, Williams had no outstanding commercial paper.

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ARO Trust (Notes)

12 Months Ended

Dec. 31, 2020

Investments, Debt and Equity Securities [Abstract]

ARO Trust

ARO TRUST

We are entitled to collect in rates the amounts necessary to fund our ARO. We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The ARO Trust carries a moderate risk portfolio. The Money Market Funds held in our ARO Trust are considered investments. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

Effective March 1, 2019, the annual ARO funding obligation based on the Docket No. RP18-1126 rate case filing was approximately $35.9 million. Pursuant to the Docket No. RP18-1126 rate case settlement, the new funding obligation (1) effective March 1, 2019 is approximately $23.8 million and (2) effective March 1, 2020 is approximately $16.0 million

Investments within the ARO Trust at fair value were as follows (in millions):

	December 31, 2020				December 31, 2019
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Money Market Funds	$	5.8	$	5.8	$	15.8	$	15.8
U.S. Equity Funds	59.9		108.0		55.3		83.3
International Equity Funds	34.2		43.7		31.8		35.4
Municipal Bond Funds	74.9		78.0		64.7		66.1
Total	$	174.8	$	235.5	$	167.6	$	200.6

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Fair Value Measurements (Notes)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of short-term financial assets (advances to affiliate and from affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
					(Millions)
Assets (liabilities) at December 31, 2020:
Measured on a recurring basis:
ARO Trust investments	$	235.5	$	235.5	$	235.5	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(5,239.8)		(6,949.0)		—		(6,949.0)		—
Assets (liabilities) at December 31, 2019:
Measured on a recurring basis:
ARO Trust investments	$	200.6	$	200.6	$	200.6	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(4,065.0)		(5,251.4)		—		(5,251.4)		—

Fair Value Methods

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP18-1126 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and are reported in Other Assets-Other on the accompanying Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 6 for more information regarding the ARO Trust.

Long-term debt - The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton and Atlantic Sunrise expansions, which are included within long-term debt, were determined using an income approach (See Note 5 - Debt and Financing Agreements).

Nonrecurring fair value measurementsApprovals required for the Northeast Supply Enhancement project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now require impairment. As of December 31, 2020, the estimated fair value of the materials within the capitalized project costs were determined to be $41.5 million and considered other internal uses and salvage values for the Property, plant, and equipment, net, a Level 3 measurement. The remaining capitalized costs were determined to have no fair value. As a result we recognized an impairment charge of $170.1 million during the fourth quarter of 2020.

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Benefit Plans (Notes)

12 Months Ended

Dec. 31, 2020

Retirement Benefits [Abstract]

Employee Benefit Plans [Text Block]

BENEFIT PLANS

Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below.

Pension and Other Postretirement Benefit Plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams were $9.1 million, $9.6 million and $12.8 million for 2020, 2019, and 2018, respectively. Included in our pension costs are settlement charges of $3.7 million and $2.7 million for 2020 and 2018, respectively.

Williams makes annual cash contributions to the pension plans, based on annual actuarial estimates, which Transco recovers through rates that are set through periodic general rate filings. Effective with the Docket No. RP18-1126 rate case settlement, any amounts of annual contributions that fall below a threshold are recorded as adjustments to income and refunded through future rate adjustments. The amounts of deferred pension collections recorded as regulatory liabilities at December 31, 2020 and 2019 were $38.9 million and $43.3 million, respectively. Effective with the Docket No. RP18-1126 rate case settlement, the pension regulatory liability as of March 1, 2019 is being amortized over a five year period.

Williams provides subsidized retiree health care and life insurance benefits to certain eligible participants. Generally, participants that were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries, are eligible for subsidized retiree health care benefits. We recognized other postretirement benefit income of $4.5 million, $4.1 million and $5.9 million for 2020, 2019, and 2018, respectively.

We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to expense and collected or refunded through future rate adjustments. The amount of other postretirement benefits costs deferred as regulatory liabilities at December 31, 2020 and 2019 are $60.9 million and $68.0 million, respectively. Effective with the Docket No. RP18-1126 rate case settlement, the other postretirement benefits regulatory liability as of March 1, 2019 is being amortized over a period of approximately five years.

Defined Contribution Plan

Williams maintains a defined contribution plan for substantially all of its employees. Williams charged us compensation expense of $9.5 million, $7.9 million, and $7.9 million in 2020, 2019, and 2018, respectively, for Williams’ company contributions to this plan.

Employee Stock-Based Compensation Plan Information

The Williams Companies, Inc. 2007 Incentive Plan, as subsequently amended and restated, (Plan) provides for Williams’ common stock-based awards to both employees and non-management directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.

Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. We are also billed for our proportionate share of Williams’ and other affiliates’ stock-based compensation expense through various allocation processes.

Total stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 was $4.0 million, $5.9 million, and $6.3 million, respectively, excluding amounts allocated from WPZ and Williams.

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Transactions with Major Customers and Affiliates (Notes)

1 Months Ended

Feb. 28, 2021

Transactions with Major Customers and Affiliates [Abstract]

Transactions with Major Customers and Affiliates

TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Major Customers

Operating revenues received from three of our major customers in 2020, 2019 and 2018 are as follows (in millions): 

	2020		2019		2018
Dominion Energy, Inc.	$	248.5	$	250.7	$	113.5
Duke Energy Corporation	232.8		222.5		194.5
The Southern Company, Inc.	216.4		216.1		166.2

Affiliates

We are a participant in Williams' cash management program, and we make advances to and receive advances from Williams. At December 31, 2020, our advances to Williams totaled approximately $642.7 million. These advances are represented by demand notes and are classified as Receivables - Advances to affiliate in the accompanying Consolidated Balance Sheet. At December 31, 2019, our advances from Williams totaled approximately $252.5 million. These advances are represented by demand notes and are classified as Payables - Advances from affiliate in the accompanying Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest expense and income are recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on Williams' excess cash at the end of each month. At December 31, 2020, the interest rate was 0.01 percent.

Included in Operating Revenues in the accompanying Consolidated Statement of Comprehensive Income for 2020, 2019 and 2018 are revenues received from affiliates of $11.4 million, $10.5 million, and $10.1 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Consolidated Statement of Comprehensive Income for 2020, 2019 and 2018 is purchased gas cost from affiliates of $5.6 million, $4.0 million, and $5.4 million, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to

us of our costs of doing business incurred by Williams. We were billed $352.1 million, $412.4 million, and $395.3 million during 2020, 2019 and 2018, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Consolidated Statement of Comprehensive Income. Included in the amounts billed to us for 2019 are costs for severance and other related costs associated with a reduction in workforce of $28.8 million.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $5.1 million, $4.4 million, and $4.7 million in 2020, 2019 and 2018, respectively.

We made equity distributions to our parent of $1,020 million, $824 million and $490 million during 2020, 2019 and 2018, respectively.

During 2020 and 2018, our parent made contributions totaling $115 million and $340 million, respectively, to us. During February 2021, our parent made an additional $60 million contribution to us.

During 2019, we recognized a non-cash distribution of $25 million to our parent related to a settlement agreement between Williams and a co-owner in our Atlantic Sunrise project. Although the agreement was between Williams and a third party, since the agreement was in part related to our Atlantic Sunrise project, the settlement amount was added to our Atlantic Sunrise project financing obligation. (See Note 5)

Effective December 31, 2019, we made a $36.6 million non-cash distribution to our parent of our interests in our wholly-owned subsidiaries, Cardinal Operating Company, LLC, Pine Needle Operating Company, LLC, TransCarolina LNG Company, LLC, and TransCardinal Company, LLC.

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

These accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

During 2020 and 2019, our overall asset retirement obligation changed as follows (in thousands): 

	2020		2019
Beginning balance	$	459,209	$	394,323
Accretion	23,142		21,806
New obligations	1,154		103
Changes in estimates of existing obligations (1)	(21,889)		49,070
Property dispositions/obligations settled	(11,115)		(6,093)
Ending balance	$	450,501	$	459,209

(1)    Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rate, current estimates for removal costs, discount rates, and the estimated remaining life of assets. The decrease in 2020 is primarily due to a decrease in the inflation rate. The increase in 2019 is primarily due to an increase in the inflation rate and a decrease in the discount rate.

We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding our ARO (See Note 6).

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Regulatory Assets and Liabilities (Notes)

12 Months Ended

Dec. 31, 2020

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES

The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2020 and December 31, 2019 are as follows (in millions):

Regulatory Assets	2020		2019
Grossed-up deferred taxes on equity funds used during construction	$	36.1	$	37.5
Asset retirement obligations	139.5		147.6
Asset retirement costs - Eminence	36.6		42.2
Deferred cash out	70.0		64.4
Fuel cost	34.1		40.2
Electric power cost	7.8		8.4
Slug catcher	6.4		6.6
Other	14.2		13.5
Total Regulatory Assets	$	344.7	$	360.4

Regulatory Liabilities	2020		2019
Negative salvage	$	504.5	$	482.6
Deferred taxes - liability	392.8		423.5
Sentinel meter station depreciation	6.8		6.6
Postretirement benefits other than pension	60.9		68.0
Pension	38.9		43.3
Other	—		0.3
Total Regulatory Liabilities	$	1,003.9	$	1,024.3

The significant regulatory assets and liabilities include:

Grossed-up deferred taxes on equity funds used during construction: Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

Asset retirement obligations: Regulatory asset balance established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates (See Note 10).

Asset retirement costs - Eminence: Regulatory asset balance associated with the Eminence Storage Field retirement costs. The regulatory asset is being recovered through our rates and is being amortized to expense consistent with the amounts collected in rates.

Deferred cash out: This amount represents the deferral of gains or losses on the purchases and sales of gas imbalances with shippers. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual cash out filing periods.

Fuel cost: This amount represents the difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual fuel tracker filing periods.

Electric power cost: This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods.

Slug catcher: This amount represents certain costs associated with the replacement of a component of a slug catcher which was included in the Docket No. RP18-1126 rate case settlement. A regulatory asset has been established to recognize the recovery of Transco’s investment in the slug catcher as it is collected through Transco’s depreciation rates and is being amortized at the onshore transmission plant depreciation rate.

Negative salvage: Our rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the cumulative residual amount of recoveries through rates, net of expenditures associated with these retirement costs.

Deferred taxes - liability: Regulatory liability balance was established as a result of a decrease to rate base deferred taxes due to a decrease to the effective federal income tax rate. The timing of the refund of the regulatory liability to rate payers is stated in the Docket No. RP18-1126 rate case settlement.

Sentinel meter station depreciation: This amount reflects the incremental depreciation being recorded related to the meter station modifications made for three of the Sentinel shippers. These modifications will be recovered through a surcharge over a defined period of time as stated in the Sentinel FERC order. The incremental depreciation represents the difference between the FERC granted depreciation rate for such facilities in the last rate case as compared to the depreciation rates in the Sentinel order which are based on the contractual terms in the surcharge agreements. The incremental depreciation will be recorded through the end of the contractual term and then will be amortized.

Postretirement benefits other than pension: We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and the amounts recovered in rates are recorded as regulatory assets or liabilities to be collected or refunded through future rate adjustments. These amounts are not included in the rate base. Effective with the Docket No. RP18-1126 rate case settlement, the other postretirement benefits regulatory liability balance as of March 1, 2019, is currently being amortized. (See Note 8).

Pension: We recover the actuarially determined pension cash contributions through rates that are set through periodic general rate filings. Effective with the Docket No. RP18-1126 rate case settlement, any amounts of annual contributions that fall below the threshold are recorded as adjustments to income and refunded through future rate adjustments. Effective with the Docket No. RP18-1126 rate case settlement, the pension regulatory liability balance as of March 1, 2019, is currently being amortized. (See Note 8).

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Regulatory Accounting

Regulatory Accounting

We are regulated by the Federal Energy Regulatory Commission (FERC). Accounting Standards Codification (ASC) Regulated Operations, (Topic 980), provides that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management's expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. We record certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations (ARO), and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements.

Basis of Presentation

Basis of Presentation

Williams’ acquisition of us in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At

December 31, 2020, the remaining property, plant and equipment allocation was approximately $0.5 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.

Principles of Consolidation

Principles of Consolidation

The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments prior to December 31, 2019 (See Note 9) consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $4.9 million and $3.2 million in 2019 and 2018, respectively. We made a $12.3 million contribution to Pine Needle in the second quarter of 2019.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; and 6) asset retirement obligations.

Revenue Recognition

Revenue Recognition

Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators.

Service revenue contracts from our gas pipeline business contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our natural gas sales contracts have a single performance obligation with revenue recognized at a point in time when the natural gas has been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset.

Operating Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual

commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following:

•Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

•Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Natural Gas Sales

In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).

Contract Liabilities

Our contract liabilities consist of advance payments from customers, which include prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods, and are classified as current or non-current according to when such amounts are expected to be recognized. Current and non-current contract liabilities are included within Accrued Liabilities and Other Long-Term Liabilities - Deferred revenue, respectively, in our Consolidated Balance Sheet.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component.

Leases

Leases

We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions. We recognize a

lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. As an accounting policy, we have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.

We used judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.

Environmental Matters

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2020, 2019 and 2018 are as follows:

Category of Property	2020-2019 (1)	2018
Gathering facilities	0% - 1.00%	1.35% - 2.50%
Storage facilities	1.86% -  2.05%	2.10% -  2.25%
Onshore transmission facilities	2.50%  -  7.13%	2.61%  -  5.00%
Offshore transmission facilities	1.25%  -  1.25%	1.20%  -  1.20%

(1)     Changes in depreciation rates in 2019 were due to placing into effect the rates in Docket No. RP18-1126

on March 1, 2019.

We record a liability and increase the basis in the underlying asset for the present value of each expected future Asset Retirement Obligations (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates.

Impairment of Long-Lived Assets

Impairment of Long-lived Assets

We evaluate our long-lived assets, including capitalized project development costs, for impairment when events or changes in circumstances indicate, in our management's judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred, we compare our management's estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

Judgments and assumptions are inherent in our estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize.

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $7.7 million, $10.5 million, and $29.2 million, for 2020, 2019 and 2018, respectively. The allowance for equity funds was $14.9 million, $28.8 million, and $87.1 million, for 2020, 2019 and 2018, respectively.

Income Taxes

Income Taxes

We are a natural gas company organized as a pass-through entity and our taxable income or loss is consolidated on the federal income tax return of our parent, Williams. We generally are treated as a pass-through entity for state and local income tax purposes, and those taxes are generally borne on a consolidated basis by Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We estimate the reserves, considering current expected credit losses (as discussed below in Accounting Standards Issued and Adopted). We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables.

Gas Imbalances

Gas Imbalances

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2020 and 2019. We utilize the average cost method of accounting for gas imbalances.

Deferred Cash Out

Most transportation imbalances are settled in cash on a monthly basis (cash-out). In accordance with our tariff, revenues received from the cash-out of transportation imbalances in excess of costs incurred are deferred and offset by the deferral of costs incurred in excess of revenues received. At the end of each annual August through July reporting period, if the cumulative revenues received exceed the costs incurred, the over recovered amounts are refunded. If the cumulative revenues received are less than the costs incurred, the net under recovered amounts are carried forward and offset against any future net over recoveries that may occur in a subsequent annual reporting period.

Inventory

Gas Inventory

We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2020 and 2019, Gas in Storage, at LIFO, was zero. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.

Materials and Supplies Inventory

All inventories are stated at average cost. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2020 and 2019.

Contingent Liabilities

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Pension and Other Postretirement Benefits

Pension and Other Postretirement Benefits

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 8.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost.

Cash Equivalents

Cash Flows from Operating Activities and Cash Equivalents

We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.

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Fair Value Measurements (Policies)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Methods

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP18-1126 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and are reported in Other Assets-Other on the accompanying Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 6 for more information regarding the ARO Trust.

Long-term debt - The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton and Atlantic Sunrise expansions, which are included within long-term debt, were determined using an income approach (See Note 5 - Debt and Financing Agreements).

Nonrecurring fair value measurementsApprovals required for the Northeast Supply Enhancement project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now require impairment. As of December 31, 2020, the estimated fair value of the materials within the capitalized project costs were determined to be $41.5 million and considered other internal uses and salvage values for the Property, plant, and equipment, net, a Level 3 measurement. The remaining capitalized costs were determined to have no fair value. As a result we recognized an impairment charge of $170.1 million during the fourth quarter of 2020.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Depreciation rates

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2020, 2019 and 2018 are as follows:

Category of Property	2020-2019 (1)	2018
Gathering facilities	0% - 1.00%	1.35% - 2.50%
Storage facilities	1.86% -  2.05%	2.10% -  2.25%
Onshore transmission facilities	2.50%  -  7.13%	2.61%  -  5.00%
Offshore transmission facilities	1.25%  -  1.25%	1.20%  -  1.20%

(1)     Changes in depreciation rates in 2019 were due to placing into effect the rates in Docket No. RP18-1126

on March 1, 2019.

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Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2020

Revenue Recognition [Abstract]

Contract with Customer, Asset and Liability [Table Text Block]

The following table presents a reconciliation of our contract liabilities:

	December 31, 2020		December 31, 2019
	(Thousands)
Balance at beginning of period	$	226,164	$	236,730
Recognized in revenue	(10,568)		(10,566)
Balance at end of period	$	215,596	$	226,164

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2020.

	Contract Liabilities		Remaining Performance Obligations
	(Thousands)
2021	$	10,566	$	2,349,047
2022	10,566		2,196,621
2023	10,566		2,040,685
2024	10,568		1,487,964
2025	10,566		1,453,924
Thereafter	162,764		12,231,530
Total	$	215,596	$	21,759,771

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Leases Leases (Tables)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

As of December 31, 2020, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:

	(Thousands)
2021	$	9,471
2022	9,611
2023	9,614
2024	9,316
2025	9,065
Thereafter	74,330
Total future lease payments	121,407
Less amount representing interest	36,497
Total obligations under operating leases	$	84,910

Lease, Cost [Table Text Block]

	Twelve Months Ended   December 31,
	2020			2019
	(Thousands)
Lease Cost:
Operating lease cost	$	9,691		$	10,276
Variable lease cost	3,135			6,867
Total lease cost	$	12,826		$	17,143
Cash paid for amounts included in the measurement of operating lease liabilities	$	3,690		$	9,986
	December 31,
	2020			2019
	(Thousands)
Other Information:
Right-of-use assets	$	78,899		$	84,979
Operating lease liabilities:
Current (included in Accrued liabilities - Other in our Consolidated Balance Sheet)	$	6,222		$	811
Lease liability	$	78,688		$	84,528
Weighted-average remaining lease term - operating leases (years)	15			15
Weighted-average discount rate - operating leases	4.66		%	4.65		%

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Debt and Financing Arrangements (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Long-term debt

At December 31, 2020 and 2019, long-term debt outstanding was as follows (in thousands): 

	2020		2019
Debentures:
7.08% due 2026	$	7,500	$	7,500
7.25% due 2026	200,000		200,000
Total debentures	207,500		207,500
Notes:
7.85% due 2026	1,000,000		1,000,000
4.0% due 2028	400,000		400,000
3.25% due 2030	700,000		—
5.4% due 2041	375,000		375,000
4.45% due 2042	400,000		400,000
4.6% due 2048	600,000		600,000
3.95% due 2050	500,000		—
Total notes	3,975,000		2,775,000
Other financing obligations	1,104,143		1,115,980
Total long-term debt, including current portion	5,286,643		4,098,480
Unamortized debt issuance costs	(32,505)		(22,876)
Unamortized debt premium and discount, net	(14,358)		(10,634)
Long-term debt due within one year	(22,640)		(20,180)
Total long-term debt	$	5,217,140	$	4,044,790

Maturities of long-term debt

Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2020, for the next five years, are as follows (in thousands): 

2021:     Other financing obligations	$	22,640
2022:     Other financing obligations	$	24,762
2023:     Other financing obligations	$	27,082
2024:     Other financing obligations	$	29,621
2025:     Other financing obligations	$	32,397

Future minimum lease payments

.

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ARO Trust (Tables)

12 Months Ended

Dec. 31, 2020

Investments, Debt and Equity Securities [Abstract]

ARO Trust

Investments within the ARO Trust at fair value were as follows (in millions):

	December 31, 2020				December 31, 2019
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Money Market Funds	$	5.8	$	5.8	$	15.8	$	15.8
U.S. Equity Funds	59.9		108.0		55.3		83.3
International Equity Funds	34.2		43.7		31.8		35.4
Municipal Bond Funds	74.9		78.0		64.7		66.1
Total	$	174.8	$	235.5	$	167.6	$	200.6

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Schedule of fair value, assets and liabilities measured on recurring basis

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of short-term financial assets (advances to affiliate and from affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
					(Millions)
Assets (liabilities) at December 31, 2020:
Measured on a recurring basis:
ARO Trust investments	$	235.5	$	235.5	$	235.5	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(5,239.8)		(6,949.0)		—		(6,949.0)		—
Assets (liabilities) at December 31, 2019:
Measured on a recurring basis:
ARO Trust investments	$	200.6	$	200.6	$	200.6	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(4,065.0)		(5,251.4)		—		(5,251.4)		—

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Transactions with Major Customers and Affiliates (Tables)

12 Months Ended

Dec. 31, 2020

Transactions with Major Customers and Affiliates [Abstract]

Schedule of revenue by major customers

Operating revenues received from three of our major customers in 2020, 2019 and 2018 are as follows (in millions): 

	2020		2019		2018
Dominion Energy, Inc.	$	248.5	$	250.7	$	113.5
Duke Energy Corporation	232.8		222.5		194.5
The Southern Company, Inc.	216.4		216.1		166.2

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation Disclosure [Abstract]

Schedule of change in asset retirement obligation

During 2020 and 2019, our overall asset retirement obligation changed as follows (in thousands): 

	2020		2019
Beginning balance	$	459,209	$	394,323
Accretion	23,142		21,806
New obligations	1,154		103
Changes in estimates of existing obligations (1)	(21,889)		49,070
Property dispositions/obligations settled	(11,115)		(6,093)
Ending balance	$	450,501	$	459,209

(1)    Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rate, current estimates for removal costs, discount rates, and the estimated remaining life of assets. The decrease in 2020 is primarily due to a decrease in the inflation rate. The increase in 2019 is primarily due to an increase in the inflation rate and a decrease in the discount rate.

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2020

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets [Table Text Block]

The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2020 and December 31, 2019 are as follows (in millions):

Regulatory Assets	2020		2019
Grossed-up deferred taxes on equity funds used during construction	$	36.1	$	37.5
Asset retirement obligations	139.5		147.6
Asset retirement costs - Eminence	36.6		42.2
Deferred cash out	70.0		64.4
Fuel cost	34.1		40.2
Electric power cost	7.8		8.4
Slug catcher	6.4		6.6
Other	14.2		13.5
Total Regulatory Assets	$	344.7	$	360.4

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities	2020		2019
Negative salvage	$	504.5	$	482.6
Deferred taxes - liability	392.8		423.5
Sentinel meter station depreciation	6.8		6.6
Postretirement benefits other than pension	60.9		68.0
Pension	38.9		43.3
Other	—		0.3
Total Regulatory Liabilities	$	1,003.9	$	1,024.3

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Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Purchase Price Allocation
Purchase price allocation, gross		$ 1,500,000
Purchase price allocation, property, plant and equipment, estimated useful lIfe		40 years
Purchase price allocation, depreciation		$ 35,000
Purchase price allocation, remaining allocation		500,000
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution		0	$ 4,908	$ 3,250
Contributions to unconsolidated affiliates	$ 12,300	0	12,250	0
Capitalized Interest Costs, Including Allowance for Funds Used During Construction [Abstract]
Allowance for funds used during construction, borrowed		7,700	10,500	29,200
Allowance for funds used during construction, equity		14,900	$ 28,800	$ 87,100
Inventory Disclosure [Abstract]
Gas in storage, LIFO		$ 0
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract		108 years
Minimum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract		1 year
Maximum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract		15 years
Gathering facilities | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates		0.00%	0.00%	1.35%
Gathering facilities | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates		1.00%	1.00%	2.50%
Storage facilities | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates		1.86%	1.86%	2.10%
Storage facilities | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates		2.05%	2.05%	2.25%
Onshore transmission facilities | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates		2.50%	2.50%	2.61%
Onshore transmission facilities | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates		7.13%	7.13%	5.00%
Offshore transmission facilities | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates		1.25%	1.25%	1.20%
Offshore transmission facilities | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates		1.25%	1.25%	1.20%
Pine Needle LNG Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			35.00%
Cardinal Pipeline Company LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			45.00%

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Revenue Recognition Contract Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2018
Revenue Recognition [Abstract]
Contract with Customer, Liability	$ 215,596	$ 226,164	$ 236,730
Recognized in revenue	(10,568)	$ (10,566)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue Recognition [Abstract]
Contract with Customer, Liability	10,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue Recognition [Abstract]
Contract with Customer, Liability	10,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue Recognition [Abstract]
Contract with Customer, Liability	10,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue Recognition [Abstract]
Contract with Customer, Liability	10,568
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue Recognition [Abstract]
Contract with Customer, Liability	10,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue Recognition [Abstract]
Contract with Customer, Liability	162,764
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue Recognition [Abstract]
Contract with Customer, Liability	215,596
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 2,349,047
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 2,196,621
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 2,040,685
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 1,487,964
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 1,453,924
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 12,231,530
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 21,759,771
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year

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Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 9,691	$ 10,276
Variable lease cost	3,135	6,867
Total lease cost	12,826	17,143
Cash paid for amounts included in the measurement of operating lease liabilities	3,690	9,986
Right-of-use assets	78,899	84,979
Current (included in Accrued liabilites - Other in our Consolidated Balance Sheet	6,222	811
Lease liability	$ 78,688	$ 84,528
Weighted-average remaining lease term - operating leases (years)	15 years	15 years
Weighted-average discount rate - operating leases	4.66%	4.65%
Prior to adopting ASU 2016, total rent expense			$ 10,800
2021	$ 9,471
2022	9,611
2023	9,614
2024	9,316
2025	9,065
Thereafter	74,330
Total future lease payments	121,407
Less amount representing interest	36,497
Total obligations under operating leases	$ 84,910

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Contingent Liabilities and Commitments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Jul. 01, 2020	Dec. 31, 2019
Other Commitments [Abstract]
Commitments for construction and acquisition of property, plant, and equipment	$ 14,000
Reserve for rate refunds	0	$ 284,300	$ 188,842
Environmental assessment and remediation
Site Contingency [Line Items]
Accrued environmental assessment and remediation costs, total	2,400		2,500
Accrued environmental assessment and remediation costs, current	700		1,200
Accrued environmental assessment and remediation costs, noncurrent	1,700		$ 1,300
Potentially responsible party at various Superfund and state waste disposal sites
Site Contingency [Line Items]
Environmental assessment and remediation costs, best estimate	$ 500

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Debt and Financing Arrangements Debt Disclosure (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	May 08, 2020
Debt Instrument [Line Items]
Total long-term debt, including current portion	$ 5,286,643,000	$ 5,286,643,000	$ 4,098,480,000
Other financing obligation	1,104,143,000	1,104,143,000	1,115,980,000
Unamortized debt issuance costs	(32,505,000)	(32,505,000)	(22,876,000)
Unamortized debt premium and discount, net	(14,358,000)	(14,358,000)	(10,634,000)
Long-term debt due within one year	22,640,000	22,640,000	20,180,000
Total long-term debt	5,217,140,000	5,217,140,000	4,044,790,000
Long-term Debt, Fiscal Year Maturity [Abstract]
2021	22,640,000	22,640,000
2022	24,762,000	24,762,000
2023	27,082,000	27,082,000
2024	29,621,000	29,621,000
2025	32,397,000	32,397,000
3.25% due 2030 [Member]
Debt Instrument [Line Items]
Long-term debt face amount				$ 700,000,000
Long-term debt interest rate				3.25%
3.95 due 2050 [Member]
Debt Instrument [Line Items]
Long-term debt face amount				$ 500,000,000
Long-term debt interest rate				3.95%
Dalton Expansion Project [Member]
Debt Instrument [Line Items]
Other financing obligation			700,000
Long-term debt face amount	254,400,000	254,400,000	256,800,000
Other Long-term Debt, Current	2,300,000	2,300,000	2,100,000
Atlantic Sunrise Project [Member]
Debt Instrument [Line Items]
Other financing obligation	827,100,000	827,100,000	839,000,000.0
Additions to other financing obligations	25,000,000	8,700,000	40,800,000
Other Long-term Debt, Current	20,300,000	20,300,000	18,100,000
Property pledged as collateral
Debt Instrument [Line Items]
Total long-term debt	$ 0	$ 0
9.0 % Other Financing Obligations [Member]
Debt Instrument [Line Items]
Long-term debt interest rate	9.00%	9.00%
Debentures
Debt Instrument [Line Items]
Total long-term debt, including current portion	$ 207,500,000	$ 207,500,000	207,500,000
Debentures | 7.08% due 2026 [Member]
Debt Instrument [Line Items]
Total long-term debt, including current portion	7,500,000	7,500,000	7,500,000
Debentures | 7.25% due 2026 [Member]
Debt Instrument [Line Items]
Total long-term debt, including current portion	200,000,000	200,000,000	200,000,000
Notes
Debt Instrument [Line Items]
Total long-term debt, including current portion	3,975,000,000	3,975,000,000	2,775,000,000
Notes | 7.85% due 2026
Debt Instrument [Line Items]
Total long-term debt, including current portion	1,000,000,000	1,000,000,000	1,000,000,000
Notes | 4.0% due 2028 [Member]
Debt Instrument [Line Items]
Total long-term debt, including current portion	400,000,000	400,000,000	400,000,000
Notes | 3.25% due 2030 [Member]
Debt Instrument [Line Items]
Total long-term debt, including current portion	700,000,000	700,000,000	0
Notes | 5.4% due 2041 [Member]
Debt Instrument [Line Items]
Total long-term debt, including current portion	375,000,000	375,000,000	375,000,000
Notes | 4.45% due 2042 [Member]
Debt Instrument [Line Items]
Total long-term debt, including current portion	400,000,000	400,000,000	400,000,000
Notes | 4.6 % due 2048 [Member]
Debt Instrument [Line Items]
Total long-term debt, including current portion	600,000,000	600,000,000	600,000,000
Notes | 3.95 due 2050 [Member]
Debt Instrument [Line Items]
Total long-term debt, including current portion	$ 500,000,000	$ 500,000,000	$ 0

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Debt and Financing Arrangements Line of Credit Facility (Details) - USD ($)	Dec. 31, 2020	Jul. 13, 2018
Swing Line Advances [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		$ 200,000,000
$4.5 billion credit facility [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		500,000,000
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		500,000,000
Williams Companies Inc [Member] | Commercial paper [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		4,000,000,000.0
Commercial paper, amount outstanding	$ 0
Williams Companies Inc [Member] | $4.5 billion credit facility [Member]
Line of Credit Facility [Line Items]
Line of credit facility, amount outstanding	0
Line of credit facility, maximum borrowing capacity		4,500,000,000
Additional amount by which credit facility can be increased		500,000,000
Letters of credit outstanding, amount	$ 0
Williams Companies Inc [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		$ 1,000,000,000.0

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ARO Trust (Details) - USD ($) $ in Millions	Dec. 31, 2020	Mar. 01, 2020	Dec. 31, 2019	Mar. 01, 2019
Debt Securities, Available-for-sale [Line Items]
Trading Securities, Equity, Cost	$ 174.8		$ 167.6
Trading Securities, Equity	235.5		200.6
Money Market Funds
Debt Securities, Available-for-sale [Line Items]
Trading Securities, Equity, Cost	5.8		15.8
Trading Securities, Equity	5.8		15.8
U.S. Equity Funds
Debt Securities, Available-for-sale [Line Items]
Trading Securities, Equity, Cost	59.9		55.3
Trading Securities, Equity	108.0		83.3
International Equity Funds
Debt Securities, Available-for-sale [Line Items]
Trading Securities, Equity, Cost	34.2		31.8
Trading Securities, Equity	43.7		35.4
Municipal Bond Funds
Debt Securities, Available-for-sale [Line Items]
Trading Securities, Equity, Cost	74.9		64.7
Trading Securities, Equity	$ 78.0		$ 66.1
External ARO trust [Member]
Debt Securities, Available-for-sale [Line Items]
Annual funding obligation		$ 16.0
External ARO trust [Member] | Rate Case filing [Member]
Debt Securities, Available-for-sale [Line Items]
Annual funding obligation				$ 35.9
External ARO trust [Member] | Rate Case settlement [Member]
Debt Securities, Available-for-sale [Line Items]
Annual funding obligation				$ 23.8

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Fair Value Measurements (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Quoted Prices In Active Markets for Identical Assets (Level 1)
Additional Fair Value Elements [Abstract]
Long-term debt. including current portion	$ 0.0	$ 0.0
Significant Other Oberservable Inputs (Level 2)
Additional Fair Value Elements [Abstract]
Long-term debt. including current portion	(6,949.0)	(5,251.4)
Significant Unobservable Inputs (Level 3)
Additional Fair Value Elements [Abstract]
Long-term debt. including current portion	0.0	0.0
Carrying Amount
Additional Fair Value Elements [Abstract]
Long-term debt. including current portion	(5,239.8)	(4,065.0)
Fair Value
Additional Fair Value Elements [Abstract]
Long-term debt. including current portion	(6,949.0)	(5,251.4)
Fair Value, Nonrecurring | Significant Unobservable Inputs (Level 3)
Additional Fair Value Elements [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure	41.5
Tangible Asset Impairment Charges	170.1
ARO Trust investments | Quoted Prices In Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract]
ARO Trust investments	235.5	200.6
ARO Trust investments | Significant Other Oberservable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract]
ARO Trust investments	0.0	0.0
ARO Trust investments | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract]
ARO Trust investments	0.0	0.0
ARO Trust investments | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract]
ARO Trust investments	235.5	200.6
ARO Trust investments | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Abstract]
ARO Trust investments	$ 235.5	$ 200.6

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Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Regulatory liabilities	$ 1,003.9	$ 1,024.3
Defined contribution plan, cost recognized	9.5	7.9	$ 7.9
Salary and Wage, Excluding Cost of Good and Service Sold [Abstract]
Allocated share-based compensation expense	4.0	5.9	6.3
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension cost	9.1	9.6	12.8
Pension Plan [Member] | Directly charged [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension cost charges to us by Williams	3.7		2.7
Pension - unamortized liability
Defined Benefit Plan Disclosure [Line Items]
Regulatory liability, deferred for future rate treatment	$ 38.9	43.3
Regulatory Liability, Amortization Period	5 years
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Other postretirement benefit (income) expense	$ (4.5)	(4.1)	$ (5.9)
Regulatory liabilities	$ 60.9	$ 68.0
Regulatory Liability, Amortization Period	5 years

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Transactions with Major Customers and Affiliates (Details) $ in Thousands		1 Months Ended	12 Months Ended
	Dec. 31, 2019 USD ($)	Feb. 28, 2021 USD ($)	Dec. 31, 2020 USD ($) employee	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Related Party Transaction [Line Items]
Advances from affiliate	$ 252,549		$ 0	$ 252,549
Advances to affiliate	0		$ 642,734	0
Related party transaction, rate			0.01%
Entity number of employees | employee			0
Expenses, related party			$ 352,100	412,400	$ 395,300
Severance Costs				28,800
Cash distributions to parent			(1,020,000)	(824,000)	(490,000)
Cash contributions from parent			115,000	0	340,000
Non-cash distribution of investments in subsidiaries	36,600
Subsequent Event [Member]
Related Party Transaction [Line Items]
Cash contributions from parent		$ 60,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Operating revenues, related party			11,400	10,500	10,100
Cost of natural gas sales, related party			5,600	4,000	5,400
Expenses, related party			(5,100)	(4,400)	(4,700)
Williams Companies Inc [Member]
Related Party Transaction [Line Items]
Advances from affiliate			642,700
Advances to affiliate	$ 252,500			252,500
Cash distributions to parent			(1,020,000)	(824,000)	(490,000)
Atlantic Sunrise Project [Member]
Related Party Transaction [Line Items]
Additions to other financing obligations				25,000
Dominion Energy, Inc.
Revenue, Major Customer [Line Items]
Operating revenues			248,500	250,700	113,500
Duke Energy Corporation
Revenue, Major Customer [Line Items]
Operating revenues			232,800	222,500	194,500
The Southern Company, Inc.
Revenue, Major Customer [Line Items]
Operating revenues			$ 216,400	$ 216,100	$ 166,200

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 459,209	$ 394,323
Accretion	23,142	21,806
New obligations	1,154	103
Changes in estimates of existing obligations (1)	(21,889)	49,070
Property dispositions/obligations settled	(11,115)	(6,093)
Ending balance	$ 450,501	$ 459,209

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Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets [Line Items]
Regulatory assets	$ 344.7	$ 360.4
Regulatory Liabilities [Line Items]
Regulatory liabilities	1,003.9	1,024.3
Negative salvage
Regulatory Liabilities [Line Items]
Regulatory liabilities	504.5	482.6
Deferred taxes - liability
Regulatory Liabilities [Line Items]
Regulatory liabilities	392.8	423.5
Sentinel meter station depreciation
Regulatory Liabilities [Line Items]
Regulatory liabilities	6.8	6.6
Postretirement benefits other than pension
Regulatory Liabilities [Line Items]
Regulatory liabilities	60.9	68.0
Pension- unamortized liability
Regulatory Liabilities [Line Items]
Regulatory liabilities	38.9	43.3
Other
Regulatory Liabilities [Line Items]
Regulatory liabilities	0.0	0.3
Grossed-up deferred taxes on equity funds used during construction
Regulatory Assets [Line Items]
Regulatory assets	36.1	37.5
Asset retirement obligations
Regulatory Assets [Line Items]
Regulatory assets	139.5	147.6
Asset retirement costs - Eminence
Regulatory Assets [Line Items]
Regulatory assets	36.6	42.2
Deferred cash out
Regulatory Assets [Line Items]
Regulatory assets	70.0	64.4
Fuel Cost
Regulatory Assets [Line Items]
Regulatory assets	34.1	40.2
Electric power cost
Regulatory Assets [Line Items]
Regulatory assets	7.8	8.4
Slug catcher
Regulatory Assets [Line Items]
Regulatory assets	6.4	6.6
Other
Regulatory Assets [Line Items]
Regulatory assets	$ 14.2	$ 13.5